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Power System Review

2015-16

Charles Darwin Centre

19 The Mall DARWIN NT 0800

Postal Address GPO Box 915 DARWIN NT 0801

Email: [email protected]

Website: www.utilicom.nt.gov.au

Power System Review 2015-16

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Purpose of this Report

The Power System Review (Review) is prepared by the Utilities Commission (Commission) in accordance with section 45 of the Electricity Reform Act (ERA).

Regular power system reporting aims to provide the routine release of comprehensive and authoritative data to industry participants, prospective participants, customers, regulators and policymakers, in order to:

support planning and monitoring activities by providing data to assist identification of the optimal investment options and facilitate coordination of investment actions;

advise on system performance against the price and service expectations; and

assist in holding electricity businesses accountable for reliability performance outcomes.

The Review provides information on the performance of the power system including:

planning information, which include demand forecasts, the adequacy of system capacity relative to forecast demand, and knowledge of planning and investment commitments;

the performance and health of the system, which includes information on system performance trends, regulatory and technical compliance (including equipment capability relative to security standards), and the findings of investigations into power system incidents; and

outcomes experienced by customers.

Disclaimer

The Review is prepared using information sourced from participants of the electricity supply industry, Northern Territory Government agencies, consultant reports, and publicly available information. The Review is in respect of the financial year ending 30 June 2016, and information was received from industry participants during 2016-17 for the Commission to undertake the review. The Commission understands the information received to be current as at December 2016. Where there have been significant developments post January 2017, the Commission has noted these developments throughout the report.

The Review contains predictions, estimates and statements based on the Commission’s interpretation of data provided by electricity industry participants and assumptions about the power system, including load growth forecasts and the effect of potential major developments in particular power systems. The Commission considers the Review is an accurate report within the normal tolerance of economic forecasts.

Any person using the information in the Review should independently verify the accuracy, completeness, reliability and suitability of the information and source data. The Commission accepts no liability (including liability to any person by reason of negligence) for any use of the information in this Review or for any loss, damage, cost or expense incurred or arising by reason of any error, negligent act, omission or misrepresentation in the information in this Review or otherwise.

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Inquiries

Any questions regarding this report should be directed to the Utilities Commission [email protected] or by phone 08 8999 5480.

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mailto:[email protected]


GlossaryTerm Definition

1P reserves Proven reserves with a reasonable certainty of being recovered

ACOD Average circuit outage duration index

2P reserves Proven and probable reserves

ACQ Annual contract quantity

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AMS Agreed minimum standards

APA APA Group

ATOD Average transformer outage duration index

Behind the meter Electricity produced by consumers behind the meter, such as residential solar energy

CIPS Channel Island power station

DAPR Distribution Annual Planning Report

DNSP Distribution network service provider

EDL EDL NGD (NT) Pty Ltd

ENI ENI Australia Limited

ENTPA Electricity Networks Third Party Access Act

ERA Electricity Reform Act

From the grid Electricity generated by entities holding generator licences. Does not include electricity generated and consumed by consumers, such as residential solar energy.

ESOO Electricity Statement of Opportunities published by AEMO – provides technical and market data and information regarding investment opportunities in the NEM over the next 10 years

ESS Code Electricity Standards of Service Code

EUE Expected unserved energy (see also USE). The Expected Unserved Energy (EUE) reliability standard is forward looking, compared to the Unserved Energy (USE) reliability standard, which is used to measure actual performance.

FCO Frequency of circuit outage index

Feeder Any of the medium-voltage lines used to distribute electric power from a substation to consumers or to smaller substations

FiT Feed-in-tariffs

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Term Definition

GMC Sustainable installed capacity

GWh Gigawatt hour

HV High voltage

I-NTEM Interim Northern Territory Electricity Market

IPP Independent power producer. Licensed IPPs are parties who do not wish to participate fully in the electricity supply market and generate electricity under contract for another generator

Jacana Jacana Energy is a government owned corporation established in accordance with the Government Owned Corporations Act. Jacana has a retail energy licence

kV Kilovolt

LNG Liquefied natural gas

Load shedding Disconnecting customers from the power system (that is, reduce load on the system) to restore frequency to the normal operating range

LOLP Loss of load probability – probabilistic analysis of the adequacy of generation capacity

LV Low Voltage

Max demand Maximum demand (or peak demand)

Min demand Minimum demand

MRL Minimum reserve level

MVA Megavolt ampere

MW Megawatt

NEGI North Eastern Gas Interconnector

NEFR National Electricity Forecasting Report

NEM National Electricity Market

NER National Electricity Rules

NGP Northern Gas Pipeline, previously known as NEGI (North Eastern Gas Pipeline)

NMP Network Management Plan (prepared by PWC)

NPD Network Price Determination

N-X Planning criteria allowing for full supply to be maintained to an area supplied by the installed capacity of N independent supply sources, with X number of those sources out of service (with X usually being the units with the largest installed capacity)

POE 10 Maximum demand projection that is expected to be exceeded, on average, one year in 10 (a 10% probability)

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Term Definition

POE 50 Maximum demand projection that is expected to be exceeded, on average, five years in 10 (a 50% probability)

p.a. Per annum

PJ Petajoules (see also TJ)

PJ/a Petajoules per annum

PJ/d Petajoules per day

PV Photovoltaic

PWC Power and Water Corporation is a government owned corporation established in accordance with the Government Owned Corporations Act. PWC has a network energy licence. It also holds retail and generation licences in respect to supplying remote and indigenous communities

PWC Networks The networks business division of PWC

RGPS Ron Goodin power station

Regulated systems Darwin-Katherine, Tennant Creek and the Alice Springs Region

Reserve plant margin Total system capacity available less the actual maximum demand (MD) for electricity in a particular year, expressed as a percentage of MD

SAIDI System Average Interruption Duration Index – the average number of minutes that a customer is without supply in a given period

SAIFI System Average Interruption Frequency Index – the average number of times a customer’s supply is interrupted in a given period

SCTC System Control Technical Code

Spinning reserves The ability to immediately and automatically increase generation or reduce demand in response to an increase or decrease in frequency

SRES Small-scale Renewable Energy Scheme STC Small-scale technology certificates

SWER Single wire earth return

System Control PWC holds a licence to conduct system control functions. An independently operated business unit within PWC, known as System Control provides these services.

T-Gen Territory Generation is a government owned corporation established in accordance with the Government Owned Corporations Act. T-Gen has a generation energy licence

TJ Terajoules (see also PJ) is 1 TJ = 1 million MJ

TNSP Transmission network service provider

UFLS Under frequency load shedding – reducing or disconnecting customer load from the power system to restore frequency to the normal operating range

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Term Definition

USE Unserved energy (see also EUE). The Expected Unserved Energy (EUE) reliability standard is forward looking, compared to the Unserved Energy (USE) reliability standard, which is used to measure actual performance.

VCR Value of customer reliability

WA WEM Western Australian wholesale electricity market

WPS Weddell power station

ZSS Zone substation

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Contents

1. Executive Summary

1.1 Introduction to the Power System Review1.2 Focus of the 2015-16 Review1.3 Key Issues and Findings

1.3.1 Supply Chain Robustness1.3.2 Structural separation and effective industry relationships1.3.3 System Planning1.3.4 Robustness of regulation1.3.5 Demand Projections (Chapter 3)1.3.6 Generation Performance (Chapter 4)1.3.7 Generation Adequacy and Reliability Outlook (Chapter 5)1.3.8 Fuel Supply (Chapter 6)1.3.9 Review of Transmission Networks and Planning (Chapter 7)1.3.10 Network Performance (Chapter 8)1.3.11 Customer Service (Chapter 9)

1.4 Commission’s Focus for the 2016-17 Review

2. Overview of the Northern Territory Power Systems

2.1 Territory Government’s Reform Agenda2.2 Overview of the Transmission and Distribution Systems2.3 Industry Participants2.4 Legislative Framework2.5 Overall System Performance – Major Incidents

3. Demand Projections

3.1.1 Methodology and Data3.2 Scenarios

3.2.1 Summary of Scenarios3.2.2 Consideration of Other Drivers3.2.3 Forecasts time period and labelling

3.3 Annual Energy Consumption Forecast3.4 Maximum Demand

3.4.1 Typical Maximum Demand3.4.2 Darwin-Katherine Maximum Demand3.4.3 Alice Springs Maximum Demand3.4.4 Tennant Creek Maximum Demand

3.5 Minimum Demand3.5.1 Darwin Katherine Minimum Demand3.5.2 Alice Springs Minimum Demand3.5.3 Tennant Creek Minimum Demand

3.6 Detailed Forecasts

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4. Generation Performance

4.1 Overview of Generating Plant4.2 2015-16 Generator Performance

4.2.1 Generation Response Reliability Standard4.2.2 Generation Response Reliability4.2.3 Generation Capacity Reliability Standard4.2.4 Generation Capacity Reliability4.2.5 Generation Capacity Reliability: Katherine4.2.6 Summary and Trend in Reliability Performance4.2.7 Standards of Service Indicators for Generation

4.3 Incident Reports: Generation4.3.1 Reporting Requirements4.3.2 Incident Reports: Darwin-Katherine4.3.3 Incident Reports: Alice Springs4.3.4 Incident Reports: Tennant Creek4.3.5 Incident Reports: Suggested improvements

4.4 Asset Management Plan Review4.4.1 Darwin-Katherine Generator Availability

4.5 Progress against Key Findings from previous Power System Reviews

5. Generation Adequacy and Reliability Outlook

5.1 Changes since the 2014-15 Power System Review5.2 Methodology and Approach5.3 Generator Adequacy Outlook

5.3.1 Generator Adequacy (N-X outlook)5.4 Generator Reliability Outlook

5.4.1 Generator Capacity Reliability5.4.2 Generator Response Reliability

6. Fuel Supply

6.1 Adequacy of Northern Territory Gas Supply6.1.1 T-Gen’s Gas Requirement6.1.2 PWC Gas Supply: annual demand6.1.3 PWC Gas Supply: maximum daily quantity6.1.4 Gas Transportation Capacity

6.2 Security of Gas Supply6.2.1 Blacktip Gas Field6.2.2 Amadeus Basin Gas6.2.3 LNG Back-up Supply6.2.4 Gas Transportation6.2.5 Diesel Backup6.2.6 Contingency Analysis – Failure of Blacktip or Gas Transportation

6.3 Potential Developments in Territory Fuel Resources6.3.1 Onshore Exploration Activity6.3.2 New Long-Term Gas Supply

7. Review of Transmission Networks and Planning

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7.1 Northern Territory Power Systems7.1.1 Darwin-Katherine Power System7.1.2 Alice Springs Power System7.1.3 Tennant Creek Power System7.1.4 Scope of Transmission Review

7.2 Transmission Network Adequacy and Reliability7.2.1 Transmission Line Utilisation7.2.2 Transmission Line Utilisation7.2.3 Terminal Station and Zone Substation Transformer Utilisation7.2.4 Fault Levels7.2.5 Voltage Control Management7.2.6 Power System Stability7.2.7 Power System Stability with Solar PV Penetration7.2.8 Transmission Network Performance7.2.9 Network Constraints

7.3 Incident Report Review - Networks7.3.1 Reporting Requirements7.3.2 Major Reportable Incidents – Transmission Network7.3.3 Recommendations arising from investigations7.3.4 Recommendations arising from investigations7.3.5 Katherine and Pine Creek Region

7.4 Assessment of PWC Networks’ Planning Mechanisms under the NMP7.4.1 Improvements to PWC’s Network Management Plan

8. Network Performance

8.1 Introduction8.2 Network Utilisation

8.2.1 Terminal Station and ZSS Utilisation8.2.2 Feeder Utilisation8.2.3 Feeder Performance

8.3 Planned and Recent Network Enhancements8.4 Reliability of Network Performance

8.4.1 Feeder Network Performance8.4.2 SAIDI and SAIFI Historical Comparison

8.5 Progress against Findings from 2013-14 Power System Review

9. Customer Service

9.1 Introduction9.2 PWC Network Services Performance

9.2.1 Reconnections and New Connections9.2.2 Quality of Supply Issues9.2.3 Network Related Activities Complaints9.2.4 Written Enquiry Response – Networks9.2.5 Telephone Call Response

9.3 Jacana Energy Retail Services Performance9.3.1 Telephone Call Response9.3.2 Retail-Related Complaints

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9.3.3 Customer Hardship Programs9.4 PWC Retail Services Performance

Appendices

A Generating Units

A.1.1 Channel IslandA.1.2 WeddellA.1.3 Shoal Bay and Pine CreekA.1.4 Katherine

A.2 Tennant CreekA.3 Alice Springs

A.3.1 Ron GoodinA.3.2 Owen SpringsA.3.3 Brewer PPAA.3.4 Uterne PPA

B Summary of Electricity Consumption and Maximum Demand Projections

C Generator Related Load Shedding

List of Figures

Figure 2-1 Major Incidents Reported in Darwin-Katherine 20

Figure 2-2 Major Incidents Reported in Alice Springs 21

Figure 2-3 Major Incidents Reported in Tennant Creek 21

Figure 3-1 Annual energy consumption forecast - Darwin-Katherine energy 26

Figure 3-2 Annual energy consumption forecast - Alice Springs energy 27

Figure 3-3 Annual energy consumption forecast - Tennant Creek energy 27

Figure 3-4 Example of daily load profile (kW) 29

Figure 3-5 Maximum demand - Darwin-Katherine 30

Figure 3-6 Maximum demand - Darwin-Katherine (Neutral scenario with solar PV generation) 31

Figure 3-7 Maximum demand - Alice Springs 32

Figure 3-8 Maximum demand - Alice Springs (Neutral scenario with solar PV generation) 32

Figure 3-9 Maximum demand - Tennant Creek 33

Figure 3-10 Maximum demand - Tennant Creek (with solar PV generation) 34

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Figure 3-11 Minimum demand - Darwin-Katherine 35

Figure 3-12 Minimum demand - Darwin-Katherine (with solar PV generation) 36

Figure 3-13 Minimum demand - Alice Springs 37

Figure 3-14 Minimum demand - Alice Springs (with solar PV capacity and generation) 38

Figure 3-15 Minimum demand - Tennant Creek 39

Figure 3-16 Minimum demand - Tennant Creek (with Solar PV capacity and generation) 39

Figure 4-1 Regional SAIDIs 47

Figure 4-2 Regional SAIFIs 47

Figure 4-3 SAIFI vs SAIDI 48

Figure 4-4 Territory Generation Asset Management Plan diagram 52

Figure 5-1 Generator adequacy: Darwin-Katherine 58

Figure 5-2 Generator adequacy: Alice Springs 59

Figure 5-3 Generator adequacy: Tennant Creek 59

Figure 5-4 Generator capacity reliability: Darwin-Katherine unserved energy 62

Figure 5-5 Generator capacity reliability: Alice Springs unserved energy 63

Figure 5-6 Spinning reserve in the Darwin-Katherine system 65

Figure 5-7 Generator capacity reliability: Tennant Creek unserved energy 66

Figure 5-8 Generator capacity reliability for Darwin-Katherine with historical forced outage rates 67

Figure 6-1 Northern Territory gas infrastructure 70

Figure 7-1 Overview of PWC operated Northern Territory power systems 79

Figure 7-2 Single line diagram of Darwin–Katherine transmission network 81

Figure 7-3 Minimum demand forecast 86

Figure 8-1: 22kV PWC feeder utilisation 97

Figure 8-2: 22kV PWC feeder utilisation 98

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Figure 9-1: Percentage of customer complaints relating to quality of supply and reliability 107

Figure 9-2: Customer complaints relating to quality by region 108

List of Tables

Table 1-1: System-Wide Maximum Demand Annual Growth Projections (P50 Basis, Neutral Scenario) 6

Table 1-2: System-Wide Minimum Demand Annual Growth Projections (P50 Basis, Neutral Scenario) 7

Table 2-1: Electricity Licence Holders at 30 June 2016 17

Table 2-2: 2015-16 Distribution SAIDI and SAIFI results segmented by feeder category 22

Table 3-1 Summary of scenarios 24

Table 3-2 Percentage of households with rooftop PV 25

Table 4-1: UFLS statistics associated with generation response reliability for 2015-16 43

Table 4-2: UFLS statistics associated with generation capacity reliability for 2015-16 44

Table 4-3 Generator response reliability outcomes 45

Table 4-4 Generator capability reliability outcomes 45

Table 4-5: Probability of CIPS and Weddell generation units being available for service 53

Table 4-6: CIPS generation units actual versus predicted availability 53

Table 4-7: 2015-16 Weddell generation units actual versus predicted availability 54

Table 4-8: 2015-16 Katherine generation units actual versus predicted availability 54

Table 5-1 Generation N-X planning criteria 57

Table 5-2 N-X margins for the neutral demand scenario 60

Table 5-3 Projected unserved energy under neutral economic growth conditions 66

Table 6-1 Gas contingency analysis 76

Table 7-1: Darwin-Katherine transmission network performance 87

Table 7-2 Incident summary 89

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Table 7-3 Recommendations to major transmission incidents 90

Table 8-1: Summary of the substation constraints (N-1 conditions) 96

Table 8-2: Forecast capital expenditure ($ million, real $2013-14 with input cost escalation) 100

Table 8-3: PWC and Ergon SAIDI and SAIFI comparison 102

Table 9-1 Connections and reconnections performance – PWC 106

Table 9-2 New Connections in urban areas to new subdivisions – PWC 107

Table 9-3 2015-16 customer complaints due to network-related activities – PWC 109

Table 9-4 Customer complaints due to network-related activities over time – PWC 109

Table 9-5 Telephone call answering reporting – Jacana Energy and PWC (2015-16) 110

Table 9-6: Breakdown on complaint numbers 112

Table 9-7 Customer hardship program summary 113

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1. Executive Summary

1.1 Introduction to the Power System Review

The Utilities Commission (Commission) is required by section 45 of the Electricity Reform Act (ERA) to prepare an annual Power System Review. The Commission has prepared the 2015-16 Power System Review (Review), which reports on power system performance, forecast demand and capacity in the Territory for 2015-16.

The Review concentrates on the Darwin-Katherine, Alice Springs and Tennant Creek power systems (referred to as the regulated systems) and is prepared with the assistance of participants in the electricity supply industry and other electricity industry stakeholders.

The information contained in the report, both that relating to future development of the Territory power system as well as that concerning current and historical performance of the system, is relevant to industry participants (current and potential) , consumer representatives and the Territory Government.

Electricity Standards of Service Code The Commission’s Electricity Standards of Service Code1 (ESS Code) establishes performance measures in the electricity supply industry in networks, generation and retail services. Electricity industry participants report annually to the Commission on performance measures contained in the ESS Code. These reports form significant input to this Review.

Technical advice and assistanceAs foreshadowed in previous reviews, the Commission has been significantly assisted by the Australian Energy Market Operator (AEMO) for this Review. AEMO’s involvement helps improve consistency with similar national reports. Specifically, AEMO assisted with demand forecasting, supply adequacy modelling and advice on power system issues. The Commission expects AEMO to provide similar assistance in future power system reviews.

Additionally, consulting firm Entura provided advice on fuel supply arrangements, customer service performance, review of major incidents, progress against findings from previous reviews and major incident reports, and assessment of historical performance of generation and network components.

1.2 Focus of the 2015-16 Review

The following developments are of particular relevance to the Territory and are among the Commission’s focus areas for this Review:

the impacts of the ongoing electricity industry reform program in the Territory (Chapter2);

the roles and responsibilities of the electricity market participants in improving the overall management of the security and reliability of the system post-structural separation of the Power and Water Corporation (PWC) (Chapter 2);

the potential impacts on demand forecasting caused by the increasing uptake of non-traditional forms of energy generation in the Territory (Chapter 3);

1 Available from the Commission’s website, www.utilicom.gov.au.

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generation reliability and distribution network feeder performance, and review of power system incidents, (Chapters 4 and 8); and

generation supply and networks adequacy to meet future demand, the power system model and spinning reserve, generation availability and response, network planning and availability, and generation and network reliability (Chapters 5 and 7).

1.3 Key Issues and Findings

This section summarises the analysis reported in the following chapters of the Review and comments on broad issues arising, and the overall effectiveness of the regulated systems, identifying issues and gaps in responsibility and regulation that may pose challenges to the ongoing reliability of the Territory’s power systems.

1.3.1 Supply Chain Robustness

Major incidents (as defined under the System Control Technical Code (SCTC)) have occurred in all three regulated systems caused by multiple contingency events, that is, an outage of multiple components of the power system.

These events may lead to (controlled) load shedding. That is, if generation supply cannot meet demand, the system requires energy demand to be reduced quickly. Demand is managed by switching selected customers off so that stability to the system can be restored, preventing further loss of supply and a system black (a complete loss of supply).

While the causes of these incidents are varied the Commission notes that preventable issues relating to the maintenance of auxiliary or secondary equipment such as fire detection, compressor plant or the like expose the supply chain to unacceptable vulnerability.

The Commission notes that the overall robustness of the Darwin-Katherine system (ability to withstand single and multiple contingency events) has improved in all aspects (generation and network). There is greater management and understanding of risks to the system and the steps to quickly restore power should load shedding occur by System Control.

While not considered a ”system black”, the Commission notes several incidents where outages on the single 132kV transmission line connecting Darwin to Katherine can lead to the loss of supply to all customers in Katherine. Further consideration needs to be given to levels of reliability experienced by customers in the Katherine region, including the economic trade-offs between reliability and the cost of operating local generation.

The Commission notes significant issues in generation reliability occurring in the Alice Springs power system as evidenced by an increase in major incidents and system risk notifications caused by generation. While acknowledging the transition occurring in the region with the replacement of old units at Ron Goodin with new sets at Owen Springs, the Commission notes the security requirements of the transition, requires very careful management.

In particular, the high penetration of solar PV from both customer installations and the Uterne station highlights the need for a holistic assessment of an optimal approach to management of system security in the Alice Springs region.

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1.3.2 Structural separation and effective industry relationships

The Territory’s electricity industry has undergone a major transformation over the past few years, with the aim of enhancing accountability for performance, achieving greater capital and operational efficiencies, and improving customer outcomes. In 2014 the major electricity generation and retail operations were separated out from the vertically integrated PWC to form separate, Government-owned businesses (Territory Generation (T-Gen) and Jacana Energy (Jacana)). The system control function continues to operate within PWC independently of PWC Networks.

This transformation process is ongoing. The sector is transitioning to the National Electricity Rules, amended for the Territory’s purposes, and a wholesale electricity market is being developed for the Darwin-Katherine system.

PWC (Networks) develops a Network Management Plan (NMP) that sets out PWC’s capital investment plans and how it intends to address challenges to capacity in its network for the next 5-year period. This NMP has been partially updated every year since 2014-15. PWC has modified the NMP to be more consistent with the Distribution Annual Planning Report (DAPR) format used in the National Electricity Market (NEM) for distribution network service providers. The Commission considers this to be a positive step.

In March 2014 the Darwin-Katherine system suffered a system black. The Commission subsequently commissioned a special technical audit of the processes and procedures in place at the time. The audit found a number of issues including a number of areas where there was partial compliance or non-compliance.

In April 2017, the Commission undertook a follow-up technical audit of PWC Networks and System Control, and T-Gen to assess if recommendations arising from the 2014 special technical audit had been implemented. The findings show that all licensees have made significant progress since 2014, for example there are now no areas on non-compliance in areas found to be non-compliant in 2014.

In the course of the audit, the Commission observed further advances in collaboration and communication among the structurally separated entities in 2015-16 (PWC Networks, PWC System Control, T-Gen, and Jacana). This collaboration is crucial in ensuring that electricity supply is reliably delivered to the end consumer, and the power system is robust enough to continue delivering supply when faced with contingencies such as the loss of a single generator or network component.

The Commission has seen improvements in focus and accountability in the separated entities, which has resulted in improved performance and increased reliability experienced by customers (the findings of the follow-up audit of the special technical audit is a practical example of these improvements).

Additionally, the importance of the independence and authority of the System Control unit has now become more evident in coordinating and directing the different components of the power system in delivering reliable supply of electricity to consumers.

Due to the long life of the assets within the Territory power systems, recent improvements in management of the systems may not give rise to immediate improvements in customer services.

1.3.3 System Planning

In April 2017, the Commission undertook a review of spinning reserve requirements as set by the System Controller and whether spinning reserve was being calculated in accordance with the SCTC and its associated Secure System Guidelines. The review finds that while System Control’s

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calculations are in accordance with existing rules, there is a need for a broader review taking into account economic considerations in setting spinning reserve level requirements.

Consistent with the review’s findings, the Commission’s view is that formal arrangements should be established for independent planning for generation adequacy that take economic trade-offs and the ability to meet system maximum demand into consideration. The Commission understands this is an issue being considered by the Territory Government as part of its review of existing wholesale market arrangements and that in the short to medium term, such responsibility is likely to sit with the System Control function of PWC.

There is significant opportunity for improvement in the current process of system planning by consideration of the value of lost load, assumptions regarding asset reliability and applying an appropriate level of security for planned outages. The assumed value of lost load or a Value of Customer Reliability (VCR) is an important planning input in determining the appropriate level of security for the system, and there is uncertainty around an appropriate VCR value for the three power systems in the Territory.

Improved system planning and clarity of an appropriate level of reliability will also allow a more coordinated and transparent response in addressing issues that go across network and generation reliability issues, such as issues in loss of supply to the Katherine and Pine Creek areas as noted in sections 4.3.2 and 7.3.5.

1.3.4 Robustness of regulation

The electricity industry in Australia is undergoing significant transition with the advent of new technologies, particularly those based on renewable energy. As the Territory progresses toward applying parts of the National Electricity Rules and at the same time grapples with the impacts of the new technologies, relevant Territory agencies (including the Commission) must continue to develop working relationships with national agencies (such as the Australian Energy Regulator (AER) and the Australian Energy Market Commission (AEMC)), receiving advice from AEMO and counterparts in other Australian jurisdictions.

This will give the Territory the best opportunity to capitalise on existing reforms being undertaken nationally and in other jurisdictions, and to contribute to the reform process where possible. The Territory is already experiencing the effects of solar PV growth in relation to system reliability and security. The impacts of increases in asynchronous generation and the displacement of traditional synchronous generation taking place across Australia may be exacerbated in the Territory due to the much smaller size of the Territory’s power systems.

Further improvements in dynamic modelling of power system performance and more formalised requirements to provide ancillary services (such as inertia and frequency control) are needed to ensure the long-term security of the regulated systems while maintaining value for customers. The Commission acknowledges that ongoing work is being undertaken by the Territory Government to establish operating rules for ancillary service requirements.

1.3.5 Demand Projections (Chapter 3)

Traditionally, demand forecasts have concentrated on forecasting grid demand and the generation requirements needed to supply this demand. However, the increasing uptake of self-sourced generation such as rooftop solar PV, which occurs ‘behind the meter’ and offsets the amount of generation needed from the grid, has introduced new challenges and complexities in forecasting demand.

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Total underlying demand, that is, the energy used and consumed at the power point, is met by the following components of supply2:

(Energy supplied from the grid) + (Energy supplied from rooftop solar PV)

Demand forecasts in Chapter 3 thus consider these two aspects:

energy demanded from the grid, and supplied by traditional sources such as commercially operated gas-fired generation (for example, plants operated by T-Gen); and

forecasts of how many rooftop solar PV installations will be built (solar uptake), simulations of how much energy these installations will generate and, consequently, how much demand from the grid will be offset from these installations.

All three regions are expected to have significant uptake of PV over the next 10 years, resulting in the percentage of households with rooftop PV installations increasing to around 30-36% by 2025-26.

The forecast in growth outlook annual energy consumption is not consistent across three power systems. The range of possible outcomes, depending on the assumptions is for mostly small declines in growth to moderate increases in growth up to 2025-26. The growth in annual demand is been offset by growth in ‘behind the meter’ solar PV installations. The most likely outcome is for demand to be reasonably stagnant over the next 10 years.

All three power systems are projected to have small increases in average maximum grid demand from 2016-17 to 2025-26, as shown in Table 1-1 for the most likely (neutral) economic growth scenario. In comparison, energy being generated from solar panels at times of maximum demand is projected to grow at a higher rate than maximum grid demand.

Table 1-1: System-Wide Maximum Demand Annual Growth Projections (P50 Basis*, Neutral Scenario)

Change in Maximum Annual Demand(from the grid)

Change in Contribution of Solar PV generation (simulated) at times of

Max Demand

Darwin-Katherine 0.77 MW p.a. (0.26% p.a.) 1.01 MW p.a. (8.42% p.a.)

Alice Springs 0.19 MW p.a. (0.33% p.a.) 0.25 MW p.a. (10.80% p.a.)

Tennant Creek 0.03 MW p.a. (0.40% p.a.) 0.02 MW p.a. (8.11% p.a.)Source: AEMO Modelling undertaken for the 2015-16 Power System Review. * The P50 basis reflects 50 per cent probability of exceedance. For example, maximum demand is expected to be exceeded once in every two years.

The Commission’s observation is that timing of maximum demand is shifting to later in the day.

Generally, during the middle of the day when rooftop solar PV generation is maximised, a decreasing amount of energy is needed from the grid, and this results in a situation where levels of minimum demand from the grid are decreasing.

As illustrated in Table 1-2, solar PV generation is expected to increase on average in all regions, and result in decreasing levels of minimum demand from the grid on an annual basis.

2 The supply (energy generated) and demand (load consumed) of electricity must be equal at all times on an instantaneous basis. Any significant deviations might lead to situations where supply is lost (load shedding).

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In certain modelling scenarios, Alice Springs might experience a scenario of negative demand, where underlying demand is completely offset by solar PV generation to a point where the energy generated from solar PV generation exceeds that being consumed.

Table 1-2: System-Wide Minimum Demand Annual Growth Projections (P50 Basis, Neutral Scenario)

Change in Minimum Annual Demand (from the grid)

Change in Contribution of Solar PV generation (simulated) at times of

Min Demand

Darwin-Katherine -2.09 MW p.a. (-2.78% p.a.) 3.83 MW p.a. (16.28% p.a.)

Alice Springs -0.53 MW p.a. (-10.28% p.a.) 0.73 MW p.a. (12.17% p.a.)

Tennant Creek -0.01 MW p.a. (-0.78% p.a.) 0.02 MW p.a. (7.87% p.a.)Source: AEMO Modelling undertaken for the 2015-16 Power System Review. The P50 basis reflects 50 per cent probability of exceedance. For example, maximum demand is expected to be exceeded once in every two years.

1.3.6 Generation Performance (Chapter 4)

The energy supplied during the 2015-16 period was:

Power SystemEnergy sent out

(GWHr)

Darwin-Katherine (ic. Katherine) 1,373

Katherine 16

Alice Springs 166

Tennant Creek 29

Source: T-Gen

In February 2016, the Territory Government announced significant capital investment, through T-Gen, to the Alice Springs and Tennant Creek power systems. The process of commissioning and testing is underway for both investments and are expected to be completed in 2017-18.

In particular, the increase in capacity of the Owen Springs power station of around 41 MW will partially offset the withdrawal of the Brewer power station (8.5 MW) and the decommissioning of Ron Goodin power station. Once completed there is expected to be a net reduction of generation capacity in Alice Springs of approximately 12 MW.

The upgrade of Tennant Creek power station will involve additional capacity of three 2 MW gas-fired spark ignition reciprocating engines and a 1.5 MW diesel-fired reciprocating engine. Offsetting this increase will be the retirement of the ‘Ruston’ diesel units, resulting in a net reduction of installed capacity of 1.3 MW.

In reviewing generation performance, the Commission considers a number of different aspects.

Specifically the Commission reviews ‘generation response reliability’ which is the level of generation reliability based on generator response and generator operating regimes, in particular, spinning reserve. Generator response reliability standards were not met in 2015-16 in all regulated systems, even after excluding the January 2016 Alice Springs system black event. Table 4-7 sets out that there were 20 under frequency load shedding events (UFLS) events across the regulated systems in 2015-16 associated with response reliability. Performance from 2014-15 across all regulated systems deteriorated (see Table 4-10).

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The second aspect of the review was related to generation capacity reliability. This represents the technical capability of the generation system to satisfy demand. This reflects the best possible performance of generation if it all connects and operates flawlessly.

While technically there were no UFLS events associated with capacity, AMEO has classified five separation events as generation capacity events. The separation events relate to the separation of Darwin from Katherine. Three of these events resulted in a loss of power to customers in Katherine, effectively resulting in a system black for Katherine. Notwithstanding these events the overall performance with regards to capacity was satisfactory.

The third aspect is to review SAIDI (duration per customer) and SAIFI (frequency per customer) measures for generation. As illustrated by Figure 4-20 and Figure 4-21 these performance measures fluctuate across the years. However, there appears to be a trend reduction in the frequency of outages across the regulated systems except for Alice Springs (noting that this measure has not included the separation events at Katherine).

This Review again highlights that a number of the reliability issues in the regulated system relate to the reliability of the existing generators, rather than capacity. There needs to be a continued focus on machine reliability rather than installing new generation. In this regard the Commission notes that T-Gen is making significant progress towards a more rigorous, properly documented system of asset management, and in projecting machine availability. However, further progress is needed to consolidate and implement these improvements.

As other generators begin to enter the market, the Commission recommends that the role of monitoring generation adequacy planning for the power systems should transfer from the current effective monopoly generation provider T-Gen to System Control.

The Commission also reiterates the need for further development of dynamic models across each of the three regions, acknowledging that significant progress has been made in this area by T-Gen and System Control.

1.3.7 Generation Adequacy and Reliability Outlook (Chapter 5)

AEMO assisted the Commission in assessing the adequacy and reliability of each of the power systems to meet future customer requirements. The Commission takes two different approaches to assessing the future risks of the system.

Firstly the Commission reviewed the ‘adequacy’ of the regulated systems. This assessment is a simple comparison of maximum demand and installed generation capacity.

This approach has to be viewed with some caution as the N-X approach works best where each individual component has very high availability (greater than 98-99 per cent). As per section 4.4.1, analysis indicates that T-Gen’s generation units may not have this level of reliability. However, this approach can still provide an early indication of issues that may need further investigation and assessment.

Table 5-16 demonstrates that, for Darwin-Katherine and Tennant Creek, there is expected to be sufficient installed capacity to meet the maximum demand under each of the strong, neutral and weak maximum demand forecasts.

After decommissioning of the Ron Goodin power station in 2018-19, the N-2 criteria is not met in Alice Springs. However, if the Brewer power station was made available then the Alice Springs network would have sufficient capacity.

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The second approach is to review the ‘reliability’ of the regulated systems. Generator reliability (capacity and response) are probabilistic approaches that quantify the anticipated reliability of the system compared with the adopted reliability standard.

Generation capacity reliability assesses the possibility of load shedding associated with insufficient generation available to bring to service to meet demand. This assessment indicated that only the most extreme generator outage timings risked breaching prescribed standards in the regulated systems.

Generation response reliability assesses the possibility of load shedding associated with insufficient spinning reserves to compensate for frequency disturbances. The modelling indicates that if the Darwin system where to operate at the minimum levels of spinning reserve then 15 to 25 per cent of unplanned outages would result in UFLS. Note that the power systems for a variety of reasons don’t always operate at the minimum, and thus this modelling is theoretical. However, it does indicate that the minimum spinning reserve is not always sufficient and under certain circumstances needs to be increased.

It is noted that various measures of generation performance provide conflicting conclusions for Alice Springs. The N-X assessment is useful in providing a relatively simple gauge to assess system reliability. This assessment indicates that there may be reliability concerns in the medium term for Alice Springs. In contrast, the probabilistic modelling considers the balance of consumer demand and generation supply at a more granular level, and considers the probability of high consumer demand coinciding with coincident generator outages leading to insufficient generation available to meet demand. This assessment indicates that only the most extreme generator outages would result in poor customer service.

The generator capacity assessment is contingent on further improvements in generator reliability from levels observed in 2015-16 in Darwin-Katherine. Continuation of observed generator outage rates in 2015-16 may put reliability at risk in Darwin-Katherine.

Thus, successful delivery and implementation of T-Gen’s asset management strategies is critical to each system having sufficient generator capacity to provide reliable supply. To manage the risk of generator response reliability issues the Commission recommends an increase in the sophistication of managing spinning reserves.

1.3.8 Fuel Supply (Chapter 6)

The Territory’s gas system security is considered to be N-1 until mid-2018, therefore one major source of gas can fail and be fully covered by supply from an alternate source, with an additional back-up arrangement from 2018 increasing gas system security to N-2 until at least 2022.

This is subject to infrastructure available to transport the gas, which does not have full redundancy on all elements of field production and plant processing.

Following the expected commencement of the operation of Jemena’s Northern Gas Pipeline (NGP) from the end of 2018, it will be necessary for the Commission to consider any impacts on security and prioritisation of gas supply in future Power System Reviews.

While stand-by diesel stocks incur a significant cost, they remain a critical part of Territory power system security, particularly south of the Darwin-Katherine system.

Availability of supply from the Blacktip gas field is a significant factor in maintaining security and availability of supply to the Territory, particularly in light of uncontracted reserves in the Amadeus Basin likely to be sold via the NGP. The Commission recommends that in the longer term,

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consideration be given to a gas procurement strategy for new supply post the end of the Blacktip gas field.

1.3.9 Review of Transmission Networks and Planning (Chapter 7)

AEMO reviewed and advised the Commission on major aspects of transmission network adequacy in Darwin-Katherine and Alice Springs and also reviewed PWC’s NMP, for transmission network planning. Tennant Creek was not included as it does not include any transmission assets. The highest voltage in the Darwin-Katherine power system is 132kV, and 66kV for Alice Springs.

PWC has substantially completed remedial work on the 132kV line from Channel Island to Hudson Creek and it may be reasonable to consider a double circuit failure as a second-order contingency event. In the NEM failure of a similar double circuit line is likely to be declared a credible event3 during lightning storms.

In system normal and post-contingent conditions, forecast maximum power flow on 132 kV, 66kV and ZSS (Zone Substations) are within their normal ratings and contingency ratings, except three ZSSs Archer, Palmerston and Strangways. PWC appears to have appropriate plans in place to address overloading through load transfers and work to install an additional transformer at Palmerston ZSS.

Maximum fault levels at 132 kV and 66 kV are within the circuit breaker interruption capability for the existing 2016-17 configuration.

Transmission network performance in 2015-16 was within the transmission reliability targets set by the Commission under the ESS Code. However, transmission connected transformer performance in 2015-16 (frequency of transformer outages – (FTO)) did not meet the transmission reliability targets set by the Commission due to two unplanned transformer outages in Darwin-Katherine.

Overall, PWC is completing several projects to meet future demand, replace ageing network system assets and generally improve network reliability and quality of supply.

Significant progress has been made on the work program to reduce the likelihood of an outage of the transmission lines between Hudson Creek, Palmerston, McMinns, Weddell and Archer substations. PWC Networks is managing substation and feeder capacity and average utilisation, with modest overloading on substations and feeders.

The total number of major incidents caused by network events is relatively low. However Pine Creek and Katherine are over represented in the total number of major events, with network faults resulting in islanding of Katherine and subsequent loss of power to the Katherine region. Of the eight major reportable network events there were five that impacted Katherine, three of which resulted in a complete loss of supply to the Katherine region.

Katherine is connected to the Darwin system by a single 132kV transmission line via the Pine Creek and Manton substations, a distance of around 300 kilometres. A fault anywhere along this line will result in the islanding of Katherine.

Four of these incidents were reported as caused by lightning. Two possible strategies exist for reducing the number of events; reduce the susceptibility of the line to lightning strikes (PWC responsibility) or increase the ability of the Pine Creek-Katherine area to maintain its own frequency (T-Gen and System Control responsibility). Both strategies should be investigated.

3 As defined in Clause 4.2.3 of the National Electricity Rules.

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1.3.10 Network Performance (Chapter 8)

PWC is also completing or has planned large network projects that reflect the need to address capacity constraints noted in its NMP at zone substation (ZSS) level.

Average substation utilisation during 2015-16 was 43 per cent and is projected to remain stable until 2019-20. While contingency loading exceeds 100 per cent at a few stations including Archer, Palmerston, Strangways, Lovegrove and Sadadeen, if PWC promptly executes contingency plans this can be tolerated.

A large number of distribution feeders have increased their loading from 30-40 per cent to 40-50 per cent, representing an improvement of the utilisation of the assets. Feeder performance, especially for worst performing feeders, has improved significantly.

The Commission notes that PWC has met its SAIDI targets since 2013-14 in all feeders, and all its SAIFI targets since 2013-14 except for CBD feeder in 2013-14. The Commission will review the targets and whether the targets are set at appropriate levels in its review of the ESS Code in mid-2017.

1.3.11 Customer Service (Chapter 9)

Improvements need to be made in PWC Networks’ reporting on quality of supply and network-related complaints; its current reporting does not allow for meaningful analysis or understanding of issues that allow it to make further improvements in this area.

Jacana has made improvements to its customer hardship program, and this may be driving reductions in hardship customer numbers and in disconnection rates.

Jacana established its own call centre in January 2016 after structural separation from PWC in 2014-15. The transition and handover of call centre operations from PWC to Jacana caused a significant deterioration in telephone answering performance in 2015-16.

The number of retail-related complaints has increased, however this appears to be due to Jacana’s adoption of a broader definition of a ‘complaint’ in line with the AER’s definition in 2015-16.

1.4 Commission’s Focus for the 2016-17 Review

In the 2016-17 Power System Review the Commission will have particular focus on:

planning and coordination of the power system, including response to emergencies from a utilities perspective and VCR rates;

demand forecasting with a continued focus on the impacts of renewable energy uptake;

generation performance, reliability and adequacy, including the appropriateness of generation adequacy assessments used, and the causes of performance;

customer impacts caused by major load shedding events, particularly in Alice Springs and Katherine;

fuel supply, including planning for security after the NGP commences;

network adequacy and reliability, with a focus on any changes resulting from the economic regulation of networks to the AER;

customer service performance, with a focus on improvements in reporting by PWC on complaints and quality of supply; and

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any impact of the Territory Government’s continued electricity market reviews and reform program.

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2. Overview of the Northern Territory Power Systems

2.1 Territory Government’s Reform Agenda

In recent years, the Territory Government has embarked on a substantial electricity sector reform program, with the aim of enhancing the efficiency and sustainability of the sector and improving services for consumers.

The Commission has seen improvements in focus and accountability in the separated entities, which has resulted in improved standards and increased reliability to customers. The Commission supports the Government establishing a robust electricity customer protection framework, particularly for smaller customers with appropriate public monitoring and reported.

To encourage retail competition that is effective and available to smaller customers, the Territory Government could consider reducing the threshold for the Electricity Pricing Order over time from the current level of 750 MWh per annum to 160 MWh per annum, with the short term impacts on customers given due consideration.

Initial reform

In 2000 the Territory Government introduced a third-party access regime for electricity networks, removed legislative restrictions on competition in the retail and generation sectors, and established the Utilities Commission as an independent industry regulator. From July 2002 the Power and Water Authority was corporatised (as PWC). PWC is a government owned corporation and is subject to oversight by a Shareholding Minister (the Treasurer) and Portfolio Minister (the Minister for Essential Services) under the Government Owned Corporations Act.

A staged approach to retail contestability was adopted. Market access was allowed initially for supply of very large customers using above 4 GWh per annum with the intention that, eventually, all electricity customers would be contestable. Prices for non-contestable customers would be set through a Pricing Order issued by the Territory Government. In 2010 retail contestability was extended to customers at all consumption levels.

However, maximum retail prices for customers with annual electricity consumption less than 750 MWh continue to be set by the Territory Government through an Electricity Pricing Order. The prices set by the Territory Government are below-cost reflective levels, requiring the government to make relatively large community service obligation (CSO) payments (of approximately $80 million per annum4) to electricity retailers.

More Recent Reforms

Building on earlier reforms, additional reforms have been developed and implemented in recent years.

The Territory Government has stated it regards the national electricity regulatory framework (the National Electricity Law (NEL) and National Electricity Rules (NER)) as representing best practice for the electricity sector in Australia. As far as possible the Government is seeking to adopt the national

4 2017-18 Northern Territory Government Budget: Agency Budget Statements, Community Service Obligations <https://budget.nt.gov.au/__data/assets/pdf_file/0008/277604/BP3-2017-18-book.pdf>

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https://budget.nt.gov.au/__data/assets/pdf_file/0008/277604/BP3-2017-18-book.pdf


electricity arrangements, including oversight from the national regulatory institutions, namely the AER, the AEMC, and receiving advice and information from AEMO. The Commission supports this policy direction.

The regulatory functions of the Commission in the electricity industry included licensing of industry participants, establishing network revenue requirements and prices charged by PWC Networks, administering the Government’s Electricity Pricing Order, establishing performance standards for the industry, and preparation of an annual Power System Review.

A key role for the Commission was the making of a Network Price Determination (NPD) for PWC. In May 2014 the Commission finalised the NPD for the fourth regulatory control period (1 July 2014 to 30 June 2019).

From 1 July 2015, network access and price regulation transferred to the AER. For the remainder of the fourth regulatory control period, the AER will administer the Commission’s 2014 NPD. The AER’s first determination for PWC Networks is to take effect in mid-2019 and will be made pursuant to the NEL and NER, with derogations as appropriate for the Territory. The NER, as applied in the Territory, necessary to support the AER’s network regulatory role, commenced in mid-2016. The Commission considers that the AEMC’s rule-making powers and expertise could be extended.

The Commission continues to maintain responsibility for network technical regulation including standards of service reporting, and power system monitoring and licensing.

In 2014, the retail and generation business units of the vertically integrated PWC were structurally separated into standalone government owned entities, Jacana and T-Gen. PWC holds licences for networks and system control5. Up to a few years before structural seperation, the system control unit was based within PWC Networks.

In May 2015, the Commission amended the SCTC to incorporate the role of System Control as the market operator of the Interim Northern Territory Electricity Market (I-NTEM) into System Control, which operates in the Darwin-Katherine system. The I-NTEM calculates and publishes prices based on existing bilateral contracts between retailers and generators in a virtual settlement process. The system control unit within PWC has taken on a role increasingly independent of PWC Networks and now reports directly to the CEO of PWC.

Future Reforms

In December 2016, the Territory Government announced the establishment of an expert panel to provide advice and inform the development of a Roadmap to Renewables Report, which seeks to ultimately deliver a target of 50 per cent renewable energy by 2030.

There continues to be growth in the application of electricity generation systems based on renewable energy in the Territory. The Territory Government’s 50 per cent renewable energy by 2030 target will provide further impetus to the uptake of renewable electricity generation. It will be important to ensure that power system security, and subsequently the delivery of continuous and reliable supply to customers in the Territory is not adversely impacted by such developments. The Commission notes that changes to the regulatory framework, including technical requirements, may be needed to maintain current levels of service and reliability for Territorians.

5 PWC also continues to hold generation and retail licences for provision of services to remote communities under the Indigenous Essential Services scheme.

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The Territory Government continues to review appropriate wholesale market arrangements, including the specification and pricing of ancillary services, increased independence of the System Control unit, and appropriate metering arrangements.

The Commission supports AEMO having an increased role in the Territory in relation to providing advice on the operation of the wholesale market, network planning, and setting technical standards for the generation sector in the medium to longer term.

2.2 Overview of the Transmission and Distribution Systems

The Territory’s transmission and distribution systems are operated by PWC Networks. The network comprises poles, wires, substations, transformers, feeders, switching, monitoring and signalling equipment involved in transporting electricity from generators to customers. PWC’s electrical networks operate at transmission voltages of 132kV and 66kV and distribution reticulation at 22kV and 11kV.

This Review focuses on the regulated systems, namely the three larger electricity systems operated in the Territory:

Darwin-Katherine system – the largest system, which supplies Darwin city, Palmerston, suburbs and surrounding areas of Darwin, the township of Katherine and its surrounding rural areas. Katherine is connected with a single 132 kV transmission line (see Figure 7-34).

Alice Springs system –PWC networks supplies the township and surrounding rural areas.

Tennant Creek system – PWC networks supplies the township of Tennant Creek and surrounding rural areas.

PWC also operates localised systems at Yulara and Kings Canyon and in communities under the Indigenous Essential Services program, including at Borroloola, Elliott, Daly Waters, Timber Creek, and Ti Tree.

The regulated systems are not connected to the national grid (the National Electricity Market) or each other. Figure 7-33 provides an overview of the Territory’s energy supply infrastructure.

The Territory has low customer and load density. The low-load density and geographical spread of customers impact on network topography, with much of the transmission and distribution network characterised by long radial (single) lines.

Various geographic and climatic factors pose major challenges for the network.

In the northern regions these include:

hot conditions;

regular cyclonic activity during the wet season;

extreme lightning activity year-round;

very high seasonal rainfall and frequent flooding;

high vegetation growth rates; and

high termite activity.

In the inland regions these include:

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hot conditions;

extreme summer-winter and day-night temperature variations; and

arid conditions and frequent dust storms.

These geographic and environmental factors influence the design criteria for the networks.

2.3 Industry Participants

Electricity industry participants licensed to operate in the regulated systems at 30 June 2016 are listed in Table 2-3. Additionally, for completeness the table also includes licence holders who provide services outside these three regions and providers who have formal exemptions.

The main licences are:

generation licences, which allow the licence holder to sell electricity into the market;

retail licences, which allow the licence holder to purchase electricity from Generators and sell to end use customers;

special licences. The independent Power Producers (IPP) licence allows a licence holder to generate electricity but only sell to an entity that holds a full generator licence. Note that this is a Territory-specific licence; and

network licence allows the licence holder to operate a network (as a monopoly provider).

System Control licence allows the licence holder to operate the power system, which includes ultimate responsibility for matching generation supply and customer demand on a day-to-day basis, by directing generators to generate (or restrict generation) so the power system operates in a safe, reliable and secure manner. The System Controller also currently determines the amount of ancillary services (such as spinning reserve) needed to ensure a secure and reliable system. In the NEM, AEMO performs similar functions.

System Control also undertakes market operation functions in Darwin-Katherine under its existing System Control licence and the authority given to it under the Electricity Reform Administration Regulations. Current functions of the market operator are within the System Control Technical Code and are limited to undertaking virtual market settlements for the I-NTEM.

PWC (System Control), through regulation, has an exemption from requiring a market operation licence for market settlement activities in the Darwin-Katherine power system.

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Table 2-3: Electricity Licence Holders at 30 June 2016

Licensees Darwin-Katherine Alice Springs Tennant Creek Other

Generation T-GenEDL NGDPWC (Berrimah power station)6

T-Gen

T-Gen PWC (remote Elliott, Daly Waters, Ti Tree, Timber Creek and Borroloola, and indigenous communities)

Generation – (IPP) EDL NGD (NT) P/LCosmo Power P/LLMS Generation P/L

Central Energy Power Uterne Power Plant P/L

Energy AustralianTKLN Solar

Special licence (isolated system)

Grote Eylandt Mining Company

Network PWC PWC PWC PWC (remote and indigenous communities)

Retail Jacana EnergyQEnergy LimitedERM Power Retail P/LRimfire EnergyEDL NGDPWC (to Jabiru)7

Jacana EnergyQEnergy LimitedERM Power Retail P/LRimfire EnergyEDL NGD

Jacana EnergyQEnergy LimitedERM Power Retail P/LRimfire EnergyEDL NGD

PWC (remote: Jabiru, Nhulunbuy, Alyangula, McArthur River Mine, and Aboriginal communities).

System Control (includes market operations)

PWC PWC PWC

Exemptions – electricity supply services

Alcan Gove (Nhulunbuy)

Exemptions – generation and retail

GPT RE (Casuarina shopping centre)

Source: Utilities Commission.

As the market develops, it is becoming more important to separate the System Control function from PWC to ensure the independence of the function. The Commission understands the Territory Government is reviewing these arrangements.

The Commission’s view is that as far as possible, due to the small size of the Territory market and associated difficulties in economies of scale in establishing a small, independent authority, the involvement of national organisations such as AEMO, which are already performing these functions, should be sought where possible, for example, in Western Australia8.

6 Berrimah Power Station is currently inactive. 7 Jabiru, while part of the Darwin-Katherine regulated network for the administrative purposes of the Electricity Reform

Act, is not physically connected to the Darwin-Katherine system.

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System Control is partly funded through a specific charge approved by the Commission and levied on retailers. The current inadequacy of this funding is likely to be amplified as System Control is facing increased functions in establishing market-related tasks such as economic dispatch arrangements, a framework for ancillary services, and dynamic models for systems and testing plant to ensure compliance with the technical codes.9 It is likely that System Control’s funding arrangements will have to be reviewed in the near future.

There are five privately owned generation businesses that held IPP licences and sold electricity via T-Gen under power purchase agreements during 2015-16. Three operate in the Darwin-Katherine system and two in the Alice Springs system.

On 20 March 2017, Central Energy Power’s commercial arrangements with T-Gen, and subsequently its IPP licence, expired. Central Energy operated a plant at the Brewer estate in Alice Springs.

2.4 Legislative Framework

The following Acts establish the electricity supply legislative framework supply in the Territory:

Utilities Commission Act 2000;

Electricity Reform Act 2000 (ERA);

Electricity Networks Third Party Access Act (ENTPA) (and Code); and

National Electricity (Northern Territory) (National Uniform Legislation) Act 2016.

The Utilities Commission Act 2000 establishes the Commission as an independent statutory body with defined roles and functions for economic regulation in the electricity, water, sewerage and port industries in the Territory.

The ERA provides the legislative framework for the operation of the electricity supply industry in the Territory. The ERA describes, among other things, the key functions and responsibilities of the Commission in the electricity industry, which include:

licensing of electricity entities;

setting minimum service levels for network reliability and power quality; and

monitoring network capacity and performance.

Section 45 of the ERA requires the Commission to prepare an annual review on power system performance and capacity in the Territory (that is, to prepare this Review).

The ENTPA10 specifies the access regime for persons wishing to access PWC’s electricity network. By doing so, the ENTPA provides a framework for establishing competition in the generation and retail sectors.

Key elements of the Third Party Access Code, a schedule under the ENTPA, include:

8 AEMO, Western Australia. Accessed 16 May 2017 <https://www.aemo.com.au/Gas/Retail-markets-and-metering/Market-procedures/Western-Australia> 9 This view was also conveyed in the Commission’s Review of Electricity System Planning and Market

Operation Roles and Structures – Final Report, December 2011, page 40.10 The Territory’s regional and remote networks are not subject to the third party access framework and the

Commission has no role in setting conditions of service and charges. These networks transport electricity to customers in the 72 communities and 82 outstations where essential services are provided through the Territory Government Indigenous Essential Services program; eight remote townships and three mining townships.

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https://www.aemo.com.au/Gas/Retail-markets-and-metering/Market-procedures/Western-Australia

https://www.aemo.com.au/Gas/Retail-markets-and-metering/Market-procedures/Western-Australia


network access terms and conditions;

provision of information;

ring fencing of regulated businesses; and

network pricing.

On 1 July 2016, the Territory adopted the National Electricity Rules, with derogations and transitional arrangements as appropriate for the Northern Territory, which was predominantly for Chapter 6 of the NER (Economic Regulation of Distribution Services) and relate to the AER’s role in the Territory. The ENTPA will be superseded by the NER (Northern Territory). Further chapters of the NER were applied from 1 July 2017. The Territory Government’s reform program is expected to seek to apply further sections of the NER as appropriate or relevant for the Territory.

2.5 Overall System Performance – Major Incidents

The overall performance of the power system’s components (network, generation, and the coordination of these components by system control) ultimately determine the impact and service standards of electricity supply to customers.

A way to understand the overall impact on customers is through analysis of events where supply is lost to customers, the steps taken to manage the system so that supply is not lost to even more customers, and whether supply is restored in a reasonable amount of time to affected customers.

Analysis in this review seeks to break-down and understand the causes of major incidents by region, giving an indication of overall system performance in each region, and the component of the supply chain that may have caused any major incidents (for example, generation, network, etc.), monitoring any trends and areas of focus on which the Commission might seek to encourage licensees to place greater focus.

Under SCTC, System Control reports to the Commission on any major incidents resulting in loss of supply to customers. The SCTC sets thresholds for major incidents as follows:

7.3.2 Major Reportable Incident A major reportable incident includes an event that caused:

a) loss of load arising from a failure of a generation asset;

b) loss of load arising from a failure of a transmission asset (or equivalent) of more than 0.1 system minute, excluding any incident where load is shed as agreed by contract;

c) an outage lasting longer than 15 minutes arising from equipment failure or operator error in a ZZS; System Control Technical Code V5 Page 54 of 86

d) an outage lasting longer than 6 hours affecting more than 200 customers and, in the opinion of the Power System Controller, should be classified as a major incident requiring comprehensive investigation; or

e) an outage lasting longer than 30 minutes affecting more than 1000 customers and, in the opinion the Power System Controller, should be classified as a major incident requiring comprehensive investigation.

As shown in Figure 2-1, there have been overall improvements in Darwin-Katherine since incident reporting commenced in November 2013. Network performance continues to be a significant proportion of the incidents caused by separation of the Katherine 132kV line, and the Commission

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focuses on these issues in network performance and the implications on generation capacity reliability in the Katherine region.

Figure 2-2 and Figure 2-3 show that generation performance has deteriorated, and significantly so in Alice Springs. The Commission focuses on generation reliability in Alice Springs in generation performance, and its potential impact on forecasting generation adequacy.

The Commission understands that significant investment in the Alice Springs region at Owen Springs power station is currently underway and undergoing commissioning, and expects to see improvements in reliability once the old sets at Ron Goodin power station are replaced with new generation sets at Owen Springs power station.

Figure 2-1 Major Incidents Reported in Darwin-Katherine

Source: Utilities Commission

Figure 2-2 Major Incidents Reported in Alice Springs

Figure 2-3 Major Incidents Reported in Tennant Creek

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Notwithstanding, the Commission observed that across the incidents, there has been improvement in the way that incidents are being managed in terms of risk management, as evidenced by detailed system risk notifications being sent to the Commission, in investigating and understanding the causes of these events, and the coordination of the restoration of supply after the loss of power.

Detailed analysis of major incidents by cause is provided in the respective chapters for generation performance () and network performance (7.3).

Table 2-4 sets out the changes in network performance and the post-event restoration of supply to customers, as reflected in distribution network SAIDI (which measures the average duration customers lose power) and SAIFI (the average frequency customers lose power) measures reported.

It illustrates that all of the targets have been met. Noting that the targets were based on the average 5-year performance of the systems prior to 2014-15, all performances are not notably below the targets indicating significant improvements since 2010-11.

Performance improvements over recent years has been mixed, especially for customers on rural long feeders.

Table 2-4: 2015-16 Distribution SAIDI and SAIFI results segmented by feeder category

Feeder categories

target standard

2013-14* results

2014-15 results

2015-16 results

Target standard

met

Improved Since 2013-14 / 2014-15

SAIDICBD 18.8 0.1 0.7 1.6 Yes No / NoUrban 136.0 52.0 127.6 113.0 Yes No / YesRural Short 496.3 229.0 372.9 339.8 Yes No / YesRural Long 2164.9 156.0 755.9 610.3 Yes No / Yes

SAIFICBD 0.4 0.6 0.1 0.0 Yes Yes / YesUrban 2.5 1.6 1.6 2.0 Yes No / NoRural Short 8.1 4.1 4.8 4.4 Yes No / yesRural Long 35.1 3.4 7.2 9.4 Yes No / No

Source: PWC Standards of Service Reports 2013-14, 2014-15 and 2015-16.

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* For the purposes of this report the Commission has chosen to remove the 2013-14 system black incident from the SAIDI data but not from the SAIFI data. This is justified on the basis that the cause of the System Black was within PWC’s control but the duration was exacerbated by generation related issues.

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3. Demand Projections

AEMO has undertaken electricity consumption, system and ZSS maximum demand projections for the regulated systems for the period of 2016-17 to 2025-26.

Traditionally, demand forecasts have concentrated on forecasting grid demand and the generation requirements needed to supply this demand. However, the increasing uptake of self-sourced generation such as rooftop solar PV, which occurs ‘behind the meter’ and offsets the amount of generation needed from the grid, has introduced new challenges and complexities in forecasting demand.

Total underlying demand, i.e. the energy used and consumed at the power point, is met by the following components of supply11:

(Energy supplied from the grid) + (Energy supplied from rooftop solar PV)

Demand forecasts in Chapter 3 thus consider these two aspects:

energy demanded from the grid, and supplied by traditional sources such as commercially operated gas-fired generation (for example, plants operated by Territory Generation); and

forecasts of how many rooftop solar PV installations will be built (solar uptake), simulations of how much energy these installations will generate, and consequently, how much demand from the grid will be offset from these installations.

This chapter provides a discussion on:

the underlying assumptions and scenarios; and

key trends and projections in maximum demand, minimum demand and ZSS maximum demand.

3.1.1 Methodology and Data

AEMO uses the same methodology in its National Electricity Forecasting Report (NEFR), adjusted as appropriate to take into consideration the limited level of data available. This methodology provides electricity consumption forecasts over a 20-year forecast period in the NEM. AEMO’s forecasting methodology is detailed in its information paper12, which accompanies the forecasts.

AEMO, as the NEM market operator, receives real-time and customer meter data in the NEM on which it bases its forecasts. Its forecasts relating to the Northern Territory are based on historical data received from industry participants such as System Control and PWC Networks.

11 The supply (energy generated) and demand (load consumed) of electricity must be equal at all times on an instantaneous basis. Any significant deviations might lead to situations where supply is lost (load shedding).

12 AEMO Forecasting Methodology Information Paper 2016. July 2016, <http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/Forecasting-Methodology-Information-Paper---2016-NEFR---Final.pdf>

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http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/Forecasting-Methodology-Information-Paper---2016-NEFR---Final.pdf

http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/Forecasting-Methodology-Information-Paper---2016-NEFR---Final.pdf


In this report we use POE 10 and POE 50. These reflect 10 per cent and 50 per cent probabilities of exceedance, respectively. For example, maximum demand will only be exceeded one in every 10 years for POE 10 and one in every two years for POE 50. Where not specifically mentioned, the POE 50 forecast is used.

3.2 Scenarios

3.2.1 Summary of Scenarios

Three scenarios reflecting strong, neutral and weak drivers of consumption is modelled at the regional level. The three scenarios are based around key drivers of demand in the Territory. Table 3-5 summarises the scenarios.

At the ZSS-level the most likely scenario, neutral, is applied.

Table 3-5 Summary of scenarios

Driver Neutral Weak StrongPopulation/Population Growth Territory Treasury

population trajectory

Weaker growth in population

Stronger growth in population

Economic growth (gross state product, Darwin-Katherine region only)

Neutral outlook Weak Strong

Solar PV (all embedded solar PV generation)13

Neutral outlook Stronger growth in installed capacity

Weaker growth in installed capacity14

Source: AEMO

3.2.2 Consideration of Other Drivers

AEMO’s scenarios do not include the effect of changes in energy efficiency of appliances and buildings. Energy efficiency of appliances and buildings is assumed to stay constant throughout the 10-year outlook period. Some gains in energy efficiency can be expected from replacement of older appliances with newer appliances, however these gains are expected to be offset by the expected increase in the number of appliances in use. Over the outlook period the impact of energy efficiency is projected to be less significant than the key drivers modelled in the scenarios.

Changes in large industrial loads can have a significant effect on networks that are of similar size to Territory power systems, especially at ZSSs. Future changes in load as notified by PWC in December 2016 have been applied to the ZSS forecasts. However, yet to be announced government or privately funded industrial and commercial developments could cause future demand to deviate from current AEMO projections.

13 Solar generation in the energy forecasts is incremental generation with 2014 as the base year.

14 Modelling by AEMO indicates that high population growth is generally associated with lower disposable income, resulting in lower uptake of domestic solar PV. Further information is available in AEMO’s Forecasting Methodology Information Paper 2016.

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Climate change is projected to influence temperatures and weather systems across Australia. Over the next 10 years the change in temperature, being the main driver of day-to-day demand at the regional-level, is uncertain and generally expected to be less than one degree Celsius.

3.2.2.1 Solar PV Uptake

To date, solar PV uptake in Australia has been sensitive to government policy, rebates and feed-in-tariffs. AEMO has assumed the current Jacana Energy feed-in tariff of 1:1 for small to medium domestic and commercial customers applies throughout the outlook period.

AEMO has also modelled the rates of residential solar PV uptake15, with growth in uptake, and installed capacity expected in all systems in the neutral (and most likely) scenario as shown below Table 3-6.

Table 3-6 Percentage of households with rooftop PV

Percentage of households with rooftop PV (%)

(neutral scenario)

2015-16 2025-26

Darwin-Katherine 11% 29%

Alice Springs 22% 34%

Tennant Creek 18% 36%

Source: AEMO

From the installed capacity levels, simulations are then undertaken based on a number of variables (such as weather, position of panels, etc.) on how much energy is being generated from the solar PV panels at times of maximum and minimum demand. These are incorporated into the maximum demand and minimum demand forecasts in sections 3.4 and 3.5 respectively.

Projections of electric vehicles and electricity storage systems (large-scale battery storage) for the eastern states of Australia suggest that these new technologies will not drive significant changes in energy consumption or demand in the outlook period. Consequently, these technologies have not been included in AEMO’s Territory forecasts. However, with advances in technology, batteries may become a greater issue over time. The Commission will look closer at this issue for the 2016-17 power system review.

3.2.3 Forecasts time period and labelling

Forecasts are for a 10 year horizon based on the assumptions above. A summary and graphical representation of key forecasts by AEMO is shown for energy consumption, maximum, and minimum demand.

Annual energy consumption refers to the energy that is generated by licenced generators, and does not include self-sourced generation ‘behind the meter’. For this chapter, we will refer to this as energy being consumed ‘from the grid’.

15

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Maximum demand (also referred to as peak demand) is the average maximum amount of energy required to be supplied by the grid at one half-hourly interval period in the year.

Minimum demand is the average minimum amount of energy required to be supplied by the grid at one half-hourly interval period in the year.

Underlying energy consumption refers to the energy that is used and consumed at the power point (for example, connected to an electrical appliance). Supply for this may be met from various sources, such as energy taken directly from the grid, or from energy generated behind the meter for example by a rooftop solar panel.

3.3 Annual Energy Consumption Forecast

The Commission has noted that low levels of growth in annual energy consumption from the grid shown in section 3.3.2 are due to underlying demand being offset by solar PV generation.

This has resulted in low levels of minimum demand, particularly those in Alice Springs, which present new challenges to the Territory similar to those faced in other Australian jurisdictions in managing frequency, and involves balancing the supply of electricity against demand on an instantaneous basis.

Large deviations from the normal frequency level or a high rate of change of frequency can cause the disconnection of generation or load, and have the potential to lead to cascading failures16 which if not managed can lead to loss of supply to customers and possibly a system black.

Figure 3-4, Figure 3-5 and Figure 3-6 show the projected annual energy consumption for the Darwin-Katherine, Alice Springs and Tennant Creek networks over the next 10 years.

Figure 3-4 Annual energy consumption forecast - Darwin-Katherine energy

Source: AEMO

As per Figure 3-4 , an increase in per annum energy consumption in Darwin-Katherine in 2015-16 to 1706 GWh (actual) from 1623 GWh in 2014-15 (actual) is expected to be followed by a decline in

16 AEMC 2017, System Security Market Frameworks Review, Directions Paper, 23 March 2017, Sydney.http://www.aemc.gov.au/getattachment/5a04b185-23f8-4690-9ad3-2a59b6010772/Directions-paper.aspx

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2016-17 in line with the key drivers of energy consumption, namely economic and population growth in the Territory.

In the neutral growth (and most likely) scenario, annual energy consumption is expected to marginally increase by 0.02 per cent per annum to an annual consumption of 1,708 GWh in 2025-26.

In the strong and weak growth scenarios, annual energy consumption is expected to change by 0.68 and -0.67 per cent per annum to an annual consumption of 1,826 GWh and 1,595 GWh in 2025-26.

Figure 3-5 Annual energy consumption forecast - Alice Springs energy

Source: AEMO

Figure 3-5 shows that in Alice Springs, there was a slight decrease in annual energy consumption from 2014-15 of 221.2 GWh (actual) to 219.0 GWh (actual) in 2015-16.

In the neutral scenario, annual energy consumption is expected to increase by 0.43 per cent per annum on average to 228.7 GWh in 2025-26. In the strong and weak growth scenarios, annual energy consumption is expected to change by 0.98 and -0.12 per cent per annum to an annual consumption of 241.5 GWh and 216.3 GWh in 2025-26.

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Figure 3-6 Annual energy consumption forecast - Tennant Creek energy

Source: AEMO

Figure 3-6 shows Tennant Creek system is a small system and annual energy consumption is expected to stay relatively stable, with small changes in annual energy consumption in 2014-15 to 2015-16 from 29.90 GWh to 29.54 GWh (actuals) followed by small increases in all scenarios.

In the neutral scenario, annual energy consumption is expected to increase by 0.44 per cent per annum on average to 30.9 GWh in 2025-26. In the strong and weak growth scenarios, annual energy consumption is expected to change by 0.79 and 0.12 per cent per annum to an annual consumption of 32.0 GWh and 29.9 GWh in 2025-26.

3.4 Maximum Demand

Having the capacity available to service maximum demand on the system at a specific point of time results in generation and network capacity being underutilised during other times of the year. This underutilisation comes at a cost for generators and networks, and ultimately for consumers.

For example, the electricity industry has installed gas-fired plants specifically designed to operate and meet maximum demand, but otherwise not operate.

Keeping maximum demand as close as possible to average demand levels reduces the underutilisation of assets and ultimately cost for consumers. This can be achieved by:

having renewable energy that can store energy and control production to produce at times of peak demand, for example, battery storage, or hydro energy;

having pricing signals setting out the relative costs of production (peak versus non-peak pricing). For example the Government’s pricing order has a ‘switch to six’ pricing tariff, which has a lower price after 6:00 pm and a higher price after 6:00 am;

maximum demand management (reducing discretionary demand at times of maximum demand – that is, paying industry, utilities and residential customers to not consume during peak periods; and

general demand management such as general reductions in energy consumption via improvements in housing and appliance energy efficiency and changes in production processes.

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This section firstly presents the range of possible outcomes for maximum demand per annum with historical actuals where available. Secondly it presents the most likely maximum demand (neutral scenario) with information on the capacity and likely level of generation from PV installations. PV installations include residential rooftop installations behind the meter.

Behind the meter installations indirectly impact on demand and capacity of a network as they replace consumption previously serviced by the grid (that is, licenced generators) and are now, at least partially, serviced by the consumer.

Adding the projected generation of solar PV installations and the maximum demand required by the grid, would give an indication of the underlying energy consumption being consumed by the customer.

3.4.1 Typical Maximum Demand

Forecast maximum demand is the highest average level of demand in a half hourly period across the year. However, while average forecasted maximum demand may be increasing slightly, the Commission observes that this may not necessarily reflect the maximum demand at a single point of time, which may be influenced by external factors and is difficult to forecast with precision. The power system must be able to continue to supply electricity instantaneously in response to spikes in maximum demand.

Demand for electricity naturally fluctuates across the day. Historically, peak periods correspond to hot afternoons and differences in climate within regions of the Territory in the northern Darwin-Katherine region compared to the southern Alice Springs and Tennant Creek regions. Consequently, maximum and minimum demand occurs at different times of the year for each regulated system.

Maximum demand occurs during winter in Tennant Creek and Alice Springs regions. The September to April period is the wet season in Darwin-Katherine, characterised by levels of high humidity. Maximum demand occurs during this period.

In 2015-16, average maximum demand (over a half-hourly interval) occurred on:

in Darwin-Katherine, on a November (wet season) weekday afternoon at about 3:30PM to 4PM, with temperatures at 33.1 degrees Celsius;

in Alice Springs, on a February (summer) weekday afternoon between 4PM to 4:30PM, temperature 39 degrees Celsius; and

in Tennant Creek, on a November (summer) weekday afternoon between 3PM to 3:30PM, temperature 40.3 degrees Celsius.

These illustrate the differences in weather and shifting patterns in times of maximum demand across the year, across the three regulated systems.

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Figure 3-7 Example of daily load profile (kW)

Source: PWC Networks

Figure 3-7 shows a general shift in the time of day when maximum demand occurs. Maximum demand has traditionally occurred during the middle of the day between 12 pm to 3 pm. However, as this coincides with the time solar PV generation is at maximum output, it offsets the demand needed from the grid.

This has caused maximum demand to occur later in the day in the evenings around 5 pm to 7 pm when the output of solar PV installations falls as the sun sets, coinciding with an increase in demand as residential households commence consuming electricity (for example, returning home from work, and dinner time).

3.4.2 Darwin-Katherine Maximum Demand

Figure 3-8 Maximum demand - Darwin-Katherine

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Source: AEMO

Actual maximum demand fluctuated (as seen from the grey line up to 2015-16) over the last five years. Figure 3-8 illustrates maximum demand in Darwin-Katherine is expected to increase by 0.26 per cent per annum to 299.0 MW in 2025-26 in the neutral scenario (blue line).

Figure 3-9 shows maximum demand (neutral scenario) for the Darwin-Katherine region and the projected PV generation of what the panels actually produce at times of maximum demand (which simulates expected underperformance based on variables such as cloud cover, weather, positioning of panels, etc. during the maximum demand period).

Figure 3-9 Maximum demand - Darwin-Katherine (Neutral scenario with solar PV generation)

Source: AEMO

Figure 3-9 shows that maximum demand from the grid is expected to show slight increases of 0.26 per cent per annum in the neutral (and most likely) scenario as shown by the blue area.

The energy generated from PV installations is expected to increase by 8.42 per cent per annum to 19.0 MW (at times of maximum demand), as shown by the yellow area.

Adding maximum demand from the grid and the simulated PV generated (the blue and yellow area) give an indication of the expected underlying maximum demand, that is, the energy used at the power point at times of maximum demand.

The modelling indicates solar PV will contribute on average 17.2 MW at times of maximum demand, offsetting demand on energy being consumed from the grid. As a result, the typical maximum demand at a time of the day, has shifted from being typically in the middle of the day to the evenings when solar PV stops generating as the sun sets, but households continue consuming energy (for example, during dinner time around 6pm).

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3.4.3 Alice Springs Maximum Demand

Figure 3-10 Maximum demand - Alice Springs

Source: AEMO

Actual maximum demand fluctuated slightly between 50 MW to 55 MW (as seen from the grey line up to 2015-16) over the last five years from 2012.

Figure 3-10 shows that maximum demand in Alice Springs is expected to increase by 0.33 per cent per annum to 56.8 MW (neutral scenario).

Figure 3-11 Maximum demand - Alice Springs (Neutral scenario with solar PV generation)

Source: AEMO

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Figure 3-11 shows that maximum demand from the grid is expected to show slight increases of 0.33 per cent per annum in the neutral (and most likely) scenario as shown by the blue area.

The energy generated from PV installations is expected to increase by 10.8 per cent per annum to 4.3 MW (at times of maximum demand), as shown by the yellow area.

Adding maximum demand from the grid and the simulated PV generated (the blue and orange area) give an indication of the expected underlying maximum demand, that is, the energy used at the power point at times of maximum demand.

Similar to analysis in Darwin-Katherine, the modelling indicates that solar PV will contribute on average nearly 3.7 MW at times of maximum demand, offsetting demand on energy consumed from the grid.

3.4.4 Tennant Creek Maximum Demand

Figure 3-12 Maximum demand - Tennant Creek

Source: AEMO

Tennant Creek is a very small system and changes in loads can have a major impact on maximum demand. Over the last five years starting from 2011-12, there were minor variations in maximum demand between 6.6 MW in 2013-14 to 7 MW in 2012-13.

Figure 3-12 shows that maximum demand in Tennant Creek is expected to increase by 0.40 per cent per annum to 7.3 MW in 2025-26 (neutral scenario).

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Figure 3-13 Maximum demand - Tennant Creek (with solar PV generation)

Source: AEMO

Figure 3-13 shows the projected contribution of generation from solar photovoltaic installations as shown in the yellow area compared to maximum demand in the neutral scenario as shown in the blue area, is expected to remain small.

Nevertheless, an individual installation may have a significant impact on the system due to the small size of the system.

3.5 Minimum Demand

Forecast minimum demand is the lowest average level of demand in a half hourly period across the year. Similar to maximum demand, this may not necessarily reflect the minimum demand at a single point in time, which may be influenced by external factors and difficult to forecast with precision.

Minimum demand has not traditionally been an area of concern for reporting purposes. However, the continued uptake of renewable energy offsetting the amount of energy needed from the grid poses new challenges to management of the power system, as the power system must be able to balance and match the supply of electricity instantaneously to demand. Ways in which this may be achieved are to increase demand to match supply (for example, by requiring an industrial load to consume more power), or to decrease supply to match demand (for example, by requiring generators to curtail their generation).

In addition, the uptake of renewable energy resulted in a shift in when minimum demand occurs from early mornings (that is, around 3:00 am) to mid-day, when solar PV is at maximum output and energy required from the grid is low, as shown previously in Figure 3-7 Example of daily load profile (kW).

As discussed in the maximum demand section, underutilised generation capacity comes at a cost to generators and ultimately consumers. Governments and the electricity industry typically encouraged consumers to increase demand during periods of minimum demand to smooth out the production of electricity as it is expensive and time consuming for large coal or gas-fired steam turbine generation plants to start and stop production – it is more efficient if they are able to operate for long periods.

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Based on rates of solar uptake, forecasts show it is possible within the next 10 years that in Alice Springs the energy supplied from the grid might be zero or negative as demand for underlying energy consumption is completely met by solar PV.

This section firstly presents the range of possible outcomes for minimum demand at one half-hourly interval during the year. Secondly it presents the most likely minimum demand (neutral scenario) with information on the capacity and likely level of generation from PV installations.

3.5.1 Darwin Katherine Minimum Demand

Figure 3-14 Minimum demand - Darwin-Katherine

Source: AEMO

Minimum demand in Darwin-Katherine is projected to decrease steadily over the next 10 years by 2.78 per cent per annum to 65.3 MW in the neutral scenario as shown in the blue line in Figure 3-14.

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Figure 3-15 Minimum demand - Darwin-Katherine (with solar PV generation)

Source: AEMO

Figure 3-15 shows minimum demand from the grid is expected to show a decrease of 2.78 per cent per annum in the neutral (and most likely) scenario as shown by the blue area.

In contrast energy generated from PV installations is expected to increase by 16.28 per cent per annum to 47.7 MW (at times of minimum demand) as shown by the orange area.

Adding minimum demand from the grid and the simulated PV generated (the blue and yellow area) give an indication of the expected underlying minimum demand, that is, the energy used at the power point at times of minimum demand.

Times of minimum demand usually coincide with times of high PV generation (that is, in the day when the sun is shining and output from solar PV is maximised).

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3.5.2 Alice Springs Minimum Demand

Figure 3-16 Minimum demand - Alice Springs

Source: AEMO

Minimum demand in Darwin-Katherine is projected to decrease steadily over the next 10 years by 10.28 per cent per annum to 2.9 MW in the neutral scenario as shown in the blue line in Figure 3-16.

In the weak scenario, negative demand17 from 2023-24 is expected to occur as a result of solar PV generation being greater than minimum demand from the grid.

17 In established energy markets with high levels of renewable energy, such a situation would result in negative energy prices where commercial customer loads are effectively paid to consume more energy to balance supply and demand of electricity.

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Figure 3-17 Minimum demand - Alice Springs (with solar PV capacity and generation)

Source: AEMO

Figure 3-17 shows minimum demand is expected to show decreases of 10.28 per cent per annum in the neutral (and most likely scenario) as shown by the blue area.

In contrast the energy generated from PV installations is expected to increase by 11.12 per cent per annum to 10.6 MW (at times of minimum demand) as shown by the yellow area.

Adding minimum demand from the grid and the simulated PV generated (the blue and yellow area) give an indication of the expected underlying minimum demand, i.e. the energy used at the power point at times of minimum demand. Times of minimum demand usually coincide with times of high PV generation (i.e. in the day when the sun is shining and output from solar PV is maximised).

Negative demand from the grid

As shown in Figure 3-16, Alice Springs is expected to experience negative demand within the next 10 years in the weak growth scenario. In this situation, underlying demand used by consumers (the combination of blue and orange areas in Figure 3-17) is positive, however this is offset by solar PV generation to a point where the energy generated from solar PV generation exceeds what is consumed.

This might result in a situation where, to balance the supply and demand of electricity, the grid is required to consume more energy (as opposed to producing more energy), increasing demand to match the increased supply of energy provided by the solar PV systems. Alternatively, generation supply would have to be curtailed, effectively lowering supply to match demand.

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3.5.3 Tennant Creek Minimum Demand

Figure 3-18 Minimum demand - Tennant Creek

Source: AEMO

Minimum demand in Tennant Creek is projected to stay flat, with negligible variations in all scenarios as shown in Figure 3-18.

Figure 3-19 Minimum demand - Tennant Creek (with Solar PV capacity and generation)

Source: AEMO

Figure 3-19 shows there will be a negligible decrease in minimum demand from the grid as shown in the blue area.

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However projected PV generation is expected to increase as shown in the yellow area, with PV generation expected to increase 7.87 per cent per annum although this is only an increase from 0.2 MW in 2016-17 to 0.4 MW in 2025-26.

As noted in 3.4.3, this indicates the significant impact an individual installation might have on the system due to the small size of the system.

3.6 Detailed Forecasts

Appendix B1, Summary of Electricity Consumption and Maximum Demand Projections, provides detailed forecasts across all three regions for:

energy consumption;

maximum demand with probability of 50 per cent exceedance – neutral scenario;

ZSS maximum demand; and

review of 2015-16 actuals versus forecasts at ZSS level.

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4. Generation Performance

Due to the relatively small size of the Territory power systems, generator-related incidents can have a significant impact on customers. The Commission continues, as per previous reviews, to undertake an assessment of generation performance that is more granular and unit-level focused than that undertaken in the NEM and other Australian jurisdictions.

This section assesses historical generation reliability performance in terms of generation response reliability, and generation capacity reliability.

The second part of this chapter makes an assessment of generation performance by reviewing generation-related incidents, T-Gen’s asset management plans and strategies, unit level availability outlook, and generation standards of service.

The chapter also notes changes in proposed generation and progress against key findings in generation performance since previous reviews.

4.1 Overview of Generating Plant

Current generation assets in the Territory

The generation plants in the Darwin-Katherine network are T-Gen’s power stations at Channel Island (310 MW), Weddell (129 MW), Katherine (35 MW), plus EDL’s Pine Creek power station (27 MW) and Shoal Bay (1.1 MW). The Darwin-Katherine power system has sustainable installed capacity of just over 500 MW. The fuel type of the generation units is made up of a mix of dual fuel (gas/diesel), gas only, steam and landfill gas.

The generation plants in the Alice Springs networks are T-Gen’s Ron Goodin (45 MW) and Owen Springs (36 MW) power stations. T-Gen also purchased electricity from Independent Power producers (IPP) at Brewer (8.5 MW) and Uterne (4.0 MW). There is a total sustainable installed capacity of approximately 90 MW in Alice Springs. The fuel type of the generation units is made up of a mix of dual fuel (gas/diesel), gas only, steam and photovoltaic.

T-Gen has approximately 17 MW installed capacity in the Tennant Creek network with a fuel type of diesel and gas.

Appendix A identifies the power stations in the three networks and the characteristics of the generating units that comprise them.

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The total energy supplied in each network is used to calculate the percentage of unserved energy. The energy supplied during the 2015-16 period was:

Power SystemEnergy sent out

(GWHr)

Darwin-Katherine (ic. Katherine) 1,373

Katherine 16

Alice Springs 166

Tennant Creek 29

Source: T-Gen

Changes to capacity in the regulated systems

In February 2016, the Territory Government announced significant capital investment, through T-Gen, to the Alice Springs and Tennant Creek power systems. The process of commissioning and testing is underway for both investments and are expected to be completed in 2017-18.

In particular, the increase in capacity of the Owen Springs power station of around 41 MW will partially offsets the withdrawal of the Brewer power station (8.5 MW) (its IPP licence expired in early 2017) and the decommissioning of Ron Goodin power station. Once completed there is expected to be a net reduction of generation capacity in Alice Springs of approximately 12 MW.

The upgrade of Tennant Creek power station will involve additional capacity of three 2 MW gas-fired spark ignition reciprocating engines and a 1.5 MW diesel-fired reciprocating engine. Offsetting this increase will be the retirement of the ‘Ruston’ diesel units, resulting in a net reduction of installed capacity of 1.3 MW.

4.2 2015-16 Generator Performance

4.2.1 Generation Response Reliability Standard

The 2013-14 review introduced ‘generation response reliability’. Generation response reliability is the level of generation reliability based on generator response and generator operating regime, in particular, spinning reserve regimes used in the Territory power systems. This includes UFLS events when there was sufficient generation available but not operating (load shedding events that are typically less than 20 minutes duration).

This reflects the actual performance of generation.

The 2013-14 review indicated that the cost of reducing UFLS by increasing the level of spinning reserve (based on the understood cost of providing generation spinning reserve) was close to the VCR. This indicates a suitable reliability standard for generation response reliability is to have no more than 0.002 per cent unserved energy (due to UFLS associated with generation response).

The Commission observed that this would not be expected to align with a loss of load probability (LOLP) of 0.1 day/per year due to the very short nature of the load shedding events associated with generation response reliability. Consequently, this review uses a standard of 0.002 per cent unserved energy for generation response reliability (noting that future work will review this).

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4.2.2 Generation Response Reliability

Table 5.1 presents for each of the regulated power systems a summary of the UFLS corresponding to generation response reliability. The table shows the number of generator outage events that resulted in load shedding, the average amount of load shed, the average time to restore demand per incident, and from this, the total amount of load shedding that occurred reported as MWh and a percentage of annual demand (providing EUE).

The information in Table 4-7 is determined from the incident reports18.

Table 4-7: UFLS statistics associated with generation response reliability for 2015-16

Power System

Number of load

Shedding Events

Estimated Average Load

Shed per EventMW

Estimated Average Event

DurationMinutes

Estimated Load Shed

MWhEstimated %

EUETargeted %

USE

Darwin-Katherine 3 40.7 43.4 96.8 0.007 0.002

Alice Springs 127.0

(4.4)*183.5(25.2)

543.7(12.7)

0.327(0.008)

0.002

Tennant Creek 5 2.3 30 5.7 0.020 0.002

* Bracketed values exclude the Alice Springs system black event. The final reports for the Tennant Creek system events do not provide sufficient information to calculate (USE / EUE) and crude approximations have been made.

Source: T-Gen

Table 4-7 shows none of the regulated systems achieved the reliability standard in 2015-16. If the system black event in Alice Springs is excluded then this system still failed to achieve the target. It is observed that the number of UFLS events was significantly higher than the LOLP standard of 0.1 day/year.

4.2.3 Generation Capacity Reliability Standard

Generation capacity reliability19 represents the technical capability of the generation system to satisfy demand. Load shedding associated with generation capacity shortages can be lengthy and severe. This reflects the best possible performance of generation if it all connects and operates flawlessly.

The previous reviews developed and presented the indices and standard of generation reliability for use in the Territory power systems. This is a LOLP of no more than one day in 10 years (or 0.027 per cent)20 or EUE of 0.002 per cent (the standard used in the NEM and the Western Australia wholesale electricity market (WA WEM)). Previous modelling showed that this reliability standard is

18 As the incident reports have differing formats between the three regions. The Commission asks that the following key information be listed in the ‘description of the incident’ table at the beginning of these reports:• Incident date and time• Description of the incident• Number of customers affected• Initiating unit/system• Root cause• Time of completed restoration• Estimated unserved energy

19 This is related to generation adequacy, which is usually associated with security.

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consistent with the economic balance associated with the cost of generation capacity in the regulated systems and a VCR of $30 000/MWh21. This was consequently the standard for generation capacity reliability.

4.2.4 Generation Capacity Reliability

During the review period the three Territory power systems did not suffer from any UFLS events associated with installed generation capacity. However, there were several system separation events where Darwin separated from Katherine and the pre-set dispatch order of generating plants meant that Katherine power station was not chosen to run, meaning loss of power to the islanded Katherine region upon separation of the networks was inevitable.

This is also discussed from a network perspective in Section 7.3.5.

These five ‘system separation’ events have been treated as generation capacity reliability events for the Katherine region.

Table 4-8: UFLS statistics associated with generation capacity reliability for 2015-16

DateEstimated Load

Shed MWDurationMinutes

Load ShedMWh % USE

8 December 15 7.1 26 3.1 0.0002

24 January 16 14.6 20 4.8 0.0003

12 March 16 27.2 26 11.8 0.0009

13 March 16 15.0 16 4.0 0.0003

9 April 16 8.4 45 6.3 0.0005

Total 29.9 0.0020

Source: T-Gen

The percent USE due to capacity reliability as shown in Table 4-8 appears to be satisfactory for the whole of the Darwin-Katherine region. However, the impact on Katherine is discussed below.

4.2.5 Generation Capacity Reliability: Katherine

The USE and loss of supply to customers for these events are all inflicted on the Katherine side of the system separation, effectively resulting in a system black for Katherine customers. The recovery of the Katherine system is nearly 30 minutes (on average).

When the annual energy output of Katherine power station is used to normalise the unserved energy then the percent unserved energy rises to 0.2 per cent or 100 times the target.

That is, if the performance of Katherine’s system was looked at in isolation to Darwin its performance is very poor. For the 2016-17 power system review the Commission will focus on the performance and standards of service to the Katherine region.

20 Historically, LOLP of 0.1 day/year was used as reliability criteria across Australia before formation of the NEM based on reliability criteria of having sufficient generation that shedding occurred no more than one day in every ten years.

21 This is less than that used in the NEM of $41 000 per MWh in 2013. This is distinguished from the market price cap in the NEM which is $13 800 for the year 2015-16.

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4.2.6 Summary and Trend in Reliability Performance

A summary of the generation reliability outcomes for 2014-15 and 2015-16 is shown in Table 4-9 and Table 4-10. The Commission currently uses a target of 0.002 per cent USE, however this target is under review.

Table 4-9 Generator response reliability outcomes

Power System 2014-15 2015-16

Darwin-Katherine 0.0020% 0.0070%

Alice Springs 0.0003% 0.3270%

Tennant Creek 0.0008% 0.0200%

*Katherine Generator Capability Reliability is 0.2% when normalised against the annual energy output of Katherine power station. See discussion in Section 5.2.2.2.

Source: T-Gen

Table 4-10 Generator capability reliability outcomes

Power System 2014-15 2015-16

Darwin-Katherine 0.009% 0.002%(0.200%)*

Alice Springs 0.000% 0.000%

Tennant Creek 0.000% 0.000%

*Katherine Generator Capability Reliability is 0.2% when normalised against the annual energy output of Katherine power station. See discussion in Section 5.2.2.2.

Source: T-Gen

The Commission also notes that assessments of generator capacity reliability are based on assumptions of all generation being operated at maximum efficiency and output, however, more granular assessments of generation performance and forced outage rates, and major incident reports in sections and 4.4 respectively suggest that these assumptions should be treated with caution.

For forecasting generator capacity reliability purposes in section 5.4.1, the Commission discusses a more probabilistic approach which incorporates the forced outage rates of generation plant.

4.2.7 Standards of Service Indicators for Generation

The following data is based on the T-Gen’s Standards of Service Report 2015-16 and previous reports for historical context. The 2012 ESS Code does not set targets for generation SAIFI and SAIDI performance, and historical performance is used as a basis of comparison, with the historical agreed minimum standards (AMS) in the previous ESS Code used to provide context. Figure 4-20 and

Source: T-Gen Standards of Service Report 2015-16 show the SAIDI and SAIFI results for the past eight years compared to the AMS.

The Commission observed in the 2012-13 and 2013-14 reviews, that the SAIDI measure for each of the regions was returning to trend. This is again true for all regions except Alice Springs which suffered several interruptions including a system black.

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Except for Alice Springs, the generation SAIDI and SAIFI measures are all within the agreed service standard.

It should be noted that while Katherine generation SAIDI and SAIFI are zero, the indicators exclude generator capacity reliability incidents caused by system separation incidents resulting from the loss of transmission interconnection with generation in Darwin, and not necessarily due to Katherine generator performance. Figure 4-22 shows SAIFI and SAIDI trends compared to the AMS.

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Figure 4-20 Regional SAIDIs

Source: T-Gen Standards of Service Report 2015-16

Figure 4-21 Regional SAIFIs


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Figure 4-22 SAIFI vs SAIDI


4.3 Incident Reports: Generation

4.3.1 Reporting Requirements

Clause 7 of the SCTC provides information on reporting requirements in relation to reportable incidents.

1. An initial report is to be provided to the Utilities Commission within 14 business days of any reportable incident. Insufficient evidence has been provided to AEMO to determine whether this requirement was adhered to for all incidents; and

2. A final report on any major reportable incident is to be provided to the Utilities Commission as soon as reasonably practical. Actual reporting timeframes varied from 71 business days to 134 business days. The average reporting time was 96 business days. By way of comparison the average reporting time in the NEM was 65 business days.

System Control is required to investigate and report on major power system incidents under SCTC, to inform the implementation of preventative measures and the response to adverse events.

There were 29 major reportable incidents during 2015-16, of which 20 related to generation. By region, there were: three reportable generation events on the Darwin-Katherine system;

twelve reportable generation events on the Alice Springs system; and

five reportable generation events on the Tennant Creek system.

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Note: The causes of the five Katherine events described in 4.2.5 have been classified as ‘network’ events. Analysis of events where the cause has been attributed to networks are in 7.3 Incident Report Review.

4.3.2 Incident Reports: Darwin-Katherine

The three reportable events on the Darwin-Katherine system each resulted in load shedding and loss of supply to 15,000 or more customers. The causes of the events were all different, an instrumentation error, a human error during equipment testing and a station air compressor failure.

The Commission considers that the compressor failure is a significant incident as it was followed by a failure of the backup compressor to start and load and also by failure of the operator to recognise that the ‘station low pressure alarm’ would (after approximately an hour) result in the tripping of both machines at Weddell power station.

At the time of each reportable generation event on the Darwin-Katherine system, the pre-event spinning reserve was 25 MW or more and achieved the target in the spinning reserve policy.

4.3.3 Incident Reports: Alice Springs

Eleven of the twelve reportable events on the Alice Springs system resulted in load shedding and loss of supply to customers but did not result in a system black. The recommendations from the eleven events are well represented by the recommendations included in a confidential report on the incidents from 27 April 2015 to 21 November 2015. As of April 2017 the Commission understands that T-Gen is in the process of addressing and implementing these recommendations. There are several recurring characteristics of these incidents:

Most of the incidents occurred at low total system load (low system inertia).

Many of the incidents were catalysed by mal-operation of a generator perhaps as the consequence of inadequate maintenance.

Many of the incidents were catalysed by machines changing from gas fuel to diesel fuel. The risk of these events could be significantly reduced by reducing the machine output to a minimum value and or increasing the spinning reserve during these operations.

For most of the events the available spinning reserve (excluding the reserve carried by a faulty machine) exceeded the amount of generation lost and yet load shedding occurred.

Local mode oscillations were observed between the three Owen Springs machines that likely contributed to the failure of machines to utilise all available spinning reserve. These oscillations are likely to be caused by an incorrectly set control system or governor and there is no evidence of a systematic investigation into this issue.

Performance of the Uterne solar station during system disturbances is not well understood. The station appears to reduce output during under frequency, under voltage or fault ride-through events. It is possible that the solar station may effectively provide a negative contribution to both spinning reserve and system inertia.

The twelfth reportable event on the Alice Springs system resulted in a system black. This event is documented in a separate confidential report. As of April 2017, the Commission understands that T-Gen is in the process of addressing and implementing these recommendations. The basic sequence of events for this incident was:

a diesel fuel supply valve started to oscillate between open and closed on RGPS set 7;

RGPS set 7 reduced its output by 4 MW;

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the frequency fell;

two stages of under frequency load shedding operated at the same moment, one based on a high set point and long-time delay, the other on a low set point and a short time delay;

excessive load was shed and the system went to over frequency;

multiple machines tripped on over frequency; and

the frequency fell again and the system collapsed.

4.3.4 Incident Reports: Tennant Creek

The five reportable events on the Tennant Creek system each resulted in load shedding and loss of supply to customers. All five events included the tripping of machine 16 while the system was at light load.

In each case machine 16 was generating more than the spinning reserve of 0.8 MW and consequently load shedding was inevitable. Three of the events were due to mal-operation of an incorrectly specified fire detector, which subsequently has been rectified.

4.3.5 Incident Reports: Suggested improvements

In accordance with the SCTC System Control provides the Commission with reports on incidents. AEMO has reviewed the major incidents reported using the following criteria:

Timeliness of the reporting process and whether the investigation process was appropriate;

Whether the recommendations arising from the investigation appear to be tracked and followed up in a systematic manner;

Any trends noted from the frequent islanding of the Katherine power system; and

Any other trends noted.

Arising from this review AEMO makes the following general comments:

the investigation methodology appears robust;

the reports are difficult to read due to the high level of technical jargon used;

the reports assume the audience has a high level of technical knowledge and knowledge of the power system. This may not be the case;

o use language appropriate to the expected audience (the Utilities Commission and Minister);

o ensure all acronyms and abbreviations are explained.

recommendations should be clearly identified and should be allocated to an organisation/team/section etc. along with an expected completion date; and

follow up reports are required detailing whether the recommendations have been completed, and if not why not. It would also set out revised completion dates.

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4.4 Asset Management Plan Review

The Commission reviewed the following confidential documents as part of this Review:

AMS-001 Asset Management System Policy – 17 June 2016;

AMS-002 Strategic Asset Management Plan – 17 June 2016;

A1.3 AMP 10 Year plan; and

Site specific asset management plans

The AMS-001 Asset Management System Policy document outlines the responsibilities assigned to various roles and the high-level objectives of the asset management system. This document is new in the 2015-16 year. For 2016-17, the Commission will seek to review whether the objectives of the document are achieved by T-Gen.

The AMS-002 Strategic Asset Management Plan document describes how T-Gen performs asset management planning, and the objectives of the process and the tools used. This document sits between the policy document and the specific plans for specific plant items.

The A1.3 AMP 10-year plan document provides the; duration, start date, finish date and location for planned maintenance and major overhaul/inspection works from July 2016 through until August 2026. This combined with the associated Gantt chart gives the Commission confidence that T-Gen has planned their outages to avoid having multiple units unavailable concurrently.

Site-specific and equipment-specific asset management plans exist for each of the major assets. These documents are new for the 2015-16 review and demonstrate clearly that T-Gen are moving towards a more rigorous, properly documented system of asset management. The Commission will review the level of implementation of T-Gen’s specific planned activities for 2016-17. The following diagram from the Weddell asset management plan shows how the various planning documents fit together.

Figure 4-23 Territory Generation Asset Management Plan diagram

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Source: T-Gen

4.4.1 Darwin-Katherine Generator Availability

T-Gen operates the Darwin-Katherine network on an N-3 capacity-planning basis. N-3 is intended to represent the following scenario:

N generation units in service to service the load;

one machine in service to provide spinning reserve;

one machine out of service for routine maintenance; and

one machine unavailable for service (long term) due to major maintenance activity such as the CIPS life extension project.

Based on this arrangement it is possible that a forced outage of one machine could lead to a scenario where it is not possible to provide any spinning reserve until the machine undergoing routine maintenance can be returned to service.

T-Gen has provided predictions of machine availability. T-Gen has based its projections on known major machine works and past reliability observations. This is a significant methodology improvement over previous years. T-Gen categorise their outages as planned, maintenance or forced outages. Maintenance outages are outages that can be deferred for 48 hours or more from the time of fault inception, but are too urgent to be delayed until the next planned outage.

From the data provided for the 2014-15 power system review for 2017-18, the Commission estimates that there will be a machine out of service at Channel Island (CIPS) or Weddell power stations for maintenance around 38 per cent of the time. For 2017-18, the data suggests one or more machines are likely to be on a forced outage 17.3 per cent of the time.

Table 4-11: Probability of CIPS and Weddell generation units being available for service

Year

One machine out for

planned outage

One machine out for

maintenance outage

One or more machines out

for forced outage

One machine out for maintenance or one

for forced outage

One machine out for maintenance and

one for forced outage

2017-18 51.8% 37.5% 17.3% 48.3% 6.5%

2018-19 41.2% 38.1% 17.5% 49.0% 6.7%

2019-20 35.7% 38.8% 17.8% 49.7% 6.9%

Source: T-Gen

Table 4-11 shows the probability of three machines out of service at the same time leaving the system without spinning reserve. The improved availability estimation method used by T-Gen has resulted in much more credible (and much higher) availability estimates than for previous years.

Table 4-12, Table 4-13 and Table 4-14 show actual vs. predicted availability for 2015-16 and actual availability trends from 2012-13 to 2014-15 for Channel Island, Weddell power station and Katherine power station, respectively.

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Table 4-12: CIPS generation units actual versus predicted availability

Machine2012-13Actual

Availability

2013-14Actual

Availability

2014-15Actual

availability

2015-16Actual

availability

2015-16Predicted

availability

Unit 1 GE Frame 6 combustion turbine (gas or diesel) 31.6 MW capacity

98.1% 97.3% 96.7% 84.6% 95.1%


0.0% 67.4% 97.3% 98.0% 85.2%


95.6% 100% 96.2% 99.6% 95.1%


99.4% 77.3% 92.4% 96.8% 89.9%


85.4% 59.7% 93.0% 92.4% 73.4%

Unit 6 Mitsubishi Steam Turbine (waste heat) 32 MW capacity

98.8% 72.5% 75.9% 92.2% 73.1%

Unit 7 GE LM6000 combustion turbine (gas or diesel) 36 MW capacity

85.1% 95.2% 96.3% 71.8% 87.4%

Unit 8 Rolls Royce Trent 60 combustion turbine (gas or diesel) 42 MW capacity

87.1% 95.5% 75.1% 87.0% 83.7%

Unit 9 Rolls Royce Trent 60 combustion turbine (gas or diesel) 42 MW capacity

66.5% 92.5% 96.3% 83.1% 89.7%

Source: T-Gen

Table 4-13: 2015-16 Weddell generation units actual versus predicted availability

Machine Actual availability Predicted availability

Unit 1 GE LM6000 combustion turbine (gas) 43.0 MW capacity 97.3% 89.5%



Source: T-Gen

Table 4-14: 2015-16 Katherine generation units actual versus predicted availability

Machine Actual availability

Predicted availability

Unit 1 Solar Mars combustion turbine (gas or diesel) 7.4 MW capacity 98.7% 96.0%



Unit 3 Solar Titan 130 combustion turbine (gas or diesel) 12.5 MW capacity 88.2% 89.9%

Source: T-Gen

The actual availability values shown in Table 4-12, Table 4-13 and Table 4-14 for T-Gen’s generation units are highly volatile, with no discernible pattern. Typically machine availability should follow one of three basic patterns:

1. increasing availability for relatively new plant;

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2. constant availability for mid-life plant; or

3. reducing availability for end of life plant.

One possible explanation for T-Gen’s generation units failing to follow one of these patterns is that the average time between failures of the generation units is following the expected pattern. However the average time to repair is highly volatile due to some external influence. The time to repair is influenced by many factors including perceived urgency of repair, availability of the other generation units, the season, network load, availability of repair staff and replacement parts, or available funding.

The Commission recommends that T-Gen move to a probabilistic approach to determining available capacity, and these methods be applied to Alice Springs and Tennant Creek generation units as well.

4.5 Progress against Key Findings from previous Power System Reviews

2014-15 PSR

The following recommendation from the last power system review is worth noting:

While improvements in availability estimation methods by T-Gen have led to greater projected availability, the Commission recommends T-Gen continue its progress in moving to a probabilistic approach to determining the available capacity at power station level.

This review remains the only mechanism, of which the Commission is aware, that looks at the capacity of the generators to meet customer demand. As the market develops and the ownership of generating stock may diversify it is the Commission’s view that the role of generators in system adequacy planning may diminish in favour of a third party. The Commission expects System Control should at least monitor this on a short and medium-term basis while the Power System Review may fulfil the need for a long-term view. The Commission acknowledges that indeed System Control does fulfil this role in the short term through its dispatch mechanism. The advent of high levels of renewable energy and changes to generation fleets, particularly in Alice Springs, may lead to the need for greater focus in this area to ensure security.

From previous reviews

At the time of publishing for the 2013-14 power system review, a major investigation into the management of under-frequency events in Darwin-Katherine was underway and the Commission highlighted a number of expected outcomes from that investigation. While the Commission acknowledges progress in this area, it remains the Commission’s view that considerable work is required by System Control and T-Gen to improve the standard of dynamic models across Darwin-Katherine and Tennant Creek regions.

Similar to previous power system reviews the Commission recommends continued development of electrical models, particularly in the Darwin-Katherine and Alice Springs systems, to identify both steady and transient stability issues must be addressed in order to fully realise the reliability benefits achievable from the significant investment in new generation in the systems. This work should specifically identify and document any deficiencies in current generator technical standards or network configuration that may be contributing to the transient stability issues in the systems, and develop a plan to redress them.

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5. Generation Adequacy and Reliability Outlook

The purpose of this chapter is to assess the adequacy and reliability of each of the power systems to meet future customer requirements.

As electricity systems are complex there are a number of ways to assess the system’s adequacy and reliability into the future. This chapter presents a couple of different methods which views the issues from different angles and with different levels of sophistication.

5.1 Changes since the 2014-15 Power System Review

Key changes since the previous power system review include:

Consideration of demand scenarios in the N-X assessment, including strong and weak sensitivities to the neutral growth scenario.

Updated maximum demand forecasts:

o Reduced maximum demand growth in Darwin-Katherine. Approximately equal to 30 MW reduced maximum demand by 2024-25. In context, that is approximately equivalent to one of the Channel Island ‘Frame 6’ power generation units; and

o Increased maximum demand growth in Alice Springs of approximately 2-3 MW by 2024-25.

Increased clarity on the re-development schedule of generation facilities at Tennant Creek and Owen Springs (compensating for retirement of the Ron Goodin power station).

Updated procedures regarding the dispatch of spinning reserve in each power system, as well as evidence of System Control's operational decisions22 to increase reserves above the minimum prescribed levels.

5.2 Methodology and Approach

Previous power system reviews adopted a standard of generation reliability for use in the Territory power systems. Generator Adequacy and Generator Reliability are used for the assessment of reliability.

The maximum demand for each system is expected during the wet season / summer months, as hot (and humid) conditions drive temperature-sensitive loads. Given the predictability of the seasonality of maximum demands, AEMO has used the wet/summer season temperature de-rated capacity of power stations in this assessment. This assumption reduces the effective installed capacity to meet the maximum demand, for example by up to 10 per cent in the Darwin-Katherine region.

Furthermore, only firm generation capacity contributes to meeting the maximum demand in this assessment. Large scale intermittent solar capacity, such as the Uterne photovoltaic development, is excluded as currently, solar generation is dependent on daylight hours and variables such as sunlight, cloud cover, etc. Thus, solar cannot be relied upon to meet maximum demand at all times. These

22 Power and Water Corporation: System Secure Guidelines (September 2016)

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assumptions result in a more conservative assessment, which needs to be considered when comparing the N-X assessment and the probabilistic assessment of generation capacity reliability.

5.3 Generator Adequacy Outlook

Generator adequacy is a traditional deterministic approach that assesses the capacity installed against the forecast maximum demand, allowing for potential outages (including planned maintenance and unit failures).

5.3.1 Generator Adequacy (N-X outlook)

This assessment is a simple comparison of maximum demand and installed generation capacity.

This approach has to be viewed with some caution as the N-X approach works best where each individual component has very high availability (greater than 98-99 per cent). As per section 4.2.7, analysis indicates that T-Gen’s generation units may not have this level of reliability. However, this approach can still provide an early indication of issues that may need further investigation and assessment.

N-X assessment determines whether there is sufficient installed capacity. It compares summer de-rated capacity to maximum demand allowing for concurrent outages of the ‘X’ largest units in each system. A system is deemed to have adequate generation capacity if there is sufficient supply to meet demand after the loss of the largest ‘X’ units.

As an extension of the n-x approach, in the 2013-14 power system review the Commission developed Minimum Reserve Levels (MRL) planning criteria, which helps determines levels of sufficient installed capacity. The planning criteria is based on a target that no more than one day in every ten years results in unserved energy associated with generation adequacy.

Generator inadequacy is identified if the summer de-rated installed capacity is less than the maximum demand + MRL. Each regional planning criteria is shown in Table 5-15.

Table 5-15 Generation N-X planning criteria

Power System N-X Standard Minimum Reserve Level (MRL)

Darwin – Katherine N – 3* 30 MWAlice Springs N – 2 13 MWTennant Creek N – 1 (gas)

N (diesel)2 MW

* The Darwin – Katherine N-3 standard is in place due to T-Gen’s life extension works of the Channel Island power station (units 1-6). From 2018-19 this is expected to revert to an N-2 standard.

Source: System Control

The assessment, as shown in Figure 5-24 to Figure 5-26, demonstrates that each system has sufficient installed or committed capacity to achieve MRL planning criteria historically used by the Commission in previous Power System Reviews, up to 2018-19.

For Darwin-Katherine – no changes in installed capacity are expected over the forecast period, and supply surpluses remain despite modest maximum demand growth. From 2018-19, following the completion of life extension works at Channel Island, the N-X criteria will adjust to an N-2 standard, from the current N-3, which will increase the supply surpluses.

In Alice Springs, the capacity of the Brewer power station (8.5 MW) is not included in this assessment, as its power purchasing agreement with T-Gen has now lapsed. The power station

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has provided only very limited generation support since March 2016. A sensitivity analysis with this capacity available is provided in the Alice Springs assessment. The development of the Owen Springs power station (41.1 MW) expected to be completed in the fourth quarter of 2017 partially offsets the withdrawal of Brewer and the decommissioning of ageing assets at Ron Goodin power station, with a net reduction of approximately 12 MW.

For Tennant Creek, this assessment includes the effect of committed new capacity at Tennant Creek and retirements of the older Tennant Creek diesel ‘Ruston’ units (a net reduction of capacity installed of 1.3 MW).

Figure 5-24 Generator adequacy: Darwin-Katherine

Source: AEMO

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Figure 5-25 Generator adequacy: Alice Springs

Source: AEMO

Figure 5-26 Generator adequacy: Tennant Creek

Source: AEMO

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The key interpretation statistics of the above assessment are provided in Table 5-16. The margin represents the N-X firm capacity available in the wet/summer above the maximum demand in each year.

Table 5-16 N-X margins for the neutral demand scenario

CriterionCompliance

with N-X until:

Margin – 2016-17 Margin – 2025-26

MW% of peak demand MW

% of peak demand

Darwin-Katherine N – 3* > 2025-26 42.64 14.1%

N – 2* > 2025-26 74.59 24.0%

Alice Springs N – 2 2019-20 9.84 17.1% - 3.20 - 5.4%

N – 2

(with Brewer)

> 2025-26 10.49 18.2% 7.75 13.0%

Tennant Creek N – 1 (gas) > 2025-26 6.71 88.5% 5.18 66.0%

* This N-3 standard is expected to apply until 2018-19 only. From 2018-19 this is expected to revert to an N-2 standard.

Source: AEMO

Table 5-16 demonstrates that, for Darwin-Katherine and Tennant Creek, there is expected to be sufficient installed capacity to meet the maximum demand under each of the strong, neutral and weak maximum demand forecasts.

For Alice Springs, the N-2 criteria is not met, under any of the scenarios after decommissioning of the Ron Goodin power station in 2018-19. However, if the Brewer power station was made available to provide maximum capacity support then the Alice Springs network would have sufficient capacity.

The ongoing availability of Brewer power station is important to the achievement of the N-2 standard in Alice Springs. Without its ongoing availability to meet maximum demands the N-X assessment shows a shortage of capacity from 2019-20.

The Brewer power station no longer has an IPP licence as its agreement with T-Gen finished in March 2017. If Central Energy, the owners of Brewer power station decide not to seek a new IPP or generator licence, then based on AEMO’s forecasts alternative energy sources will need to be developed.

5.4 Generator Reliability Outlook

Generator reliability is a probabilistic approach that quantifies the anticipated reliability of the system compared with the adopted reliability standard. Within this probabilistic assessment, two alternate methods are used to assess the adequacy of installed capacity, as well as the adequacy of dynamic ancillary services to manage risks associated with frequency control in the event of generator failures.

This is a LOLP of no more than one day in 10 years (or 0.027 per cent)23 or an EUE of 0.002 per cent (the standard used in the NEM and the WA WEM). This reliability standard is also referred to as the

23 Historically, LOLP of 0.1 day/year was used as reliability criteria across Australia before formation of the NEM based on reliability criteria of having sufficient generation that shedding occurred no more than one day in every 10 years.

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standard for ‘generation capacity reliability’. This is distinct from ‘generation response reliability’, which is also set at a standard of 0.002 per cent unserved energy (due to UFLS associated with generation response).

Further discussion on the adoption of the NEM 0.002 per cent standard is presented in Section of this report. The matter will also need consideration as part of the development of wholesale market arrangements for the Territory.

In the NEM, AEMO publishes an Electricity Statement of Opportunities (ESOO) report that similarly assesses the adequacy of generation capacity to meet the NEM’s reliability standard which sets an expectation that demand will be met 99.998 per cent of the time each financial year.

5.4.1 Generator Capacity Reliability

Generation capacity reliability assesses the possibility of load shedding associated with insufficient generation available to bring to service to meet demand. The duration of this form of load shedding (loss of supply to customers) is typically severe and widespread.

Hourly market modelling simulations are used across 150 Monte Carlo iterations, assessing alternative combinations of random generator outages. These simulations identify the probability of installed capacity being insufficient to meet demand given the likelihood of coincident outages across the generation portfolio in each system. Forced outage rates and maintenance schedules are critical inputs to this assessment.

For Darwin-Katherine, dispatch is co-optimised with dynamic spinning reserve requirements with consideration of the largest generator contingencies in each dispatch period.

AEMO has used a probabilistic assessment to simultaneously determine the reliability outlook of each Territory regulated system, as is done in the NEM. The most likely scenario, the neutral economic growth scenario has been modelled.

To assess the reliability of generator capacity over the outlook period, consideration of the availability of generation units is necessary. Planned and unplanned outages have been modelled.

Planned outages

Generator maintenance periods have been assumed to be timed in accordance with T-Gen’s current Asset Management Plan. For generators outside of T-Gen’s portfolio, an annual maintenance period of approximately 10 – 20 days average duration is also modelled. The timing of this maintenance may be planned to meet the commercial objectives of each plant operator, and is not expected to be optimised to ‘best fit’ with T-Gen’s own schedule. In the assessment, IPP units are assigned maintenance to coincide with times of high capacity reserves across each simulation year in the model.

Unplanned outages

Generator unplanned outages are modelled in a probabilistic manner, using Monte Carlo techniques24. The timing of these are randomly allocated by the model. The forced outage rate of each generator is approximately 1-2 per cent 25, depending on the generating unit, with a mean time to repair each unit of approximately 3.5 days. In 2015-16 the observed forced outage rate across

24 A total of 150 Monte Carlo iterations have been modelled, with 100 POE 10 and 50 POE 50 iterations.

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many T-Gen units were higher than this assumption. A sensitivity has been performed to assess the impact of this higher rate, as published by T-Gen in their 2015-16 Standards of Service Report.

For each region, under neutral demand growth forecasts, no breach of the reliability standard is projected. Figure 5-27 to Figure 5-31 demonstrate the modelled expected unserved energy, as well as the balance of installed capacity against projected peak demands.

Figure 5-27 shows installed capacity and projected unserved energy for the Darwin-Katherine network.

Figure 5-27 Generator capacity reliability: Darwin-Katherine unserved energy

Installed Capacity (summer de-rated) Projected unserved energy

Source: AEMO

The expected unserved energy26 in the Darwin-Katherine network is well below the standard, at 0.00004 per cent. Across the modelling there were conditions whereby expected unserved energy could breach the standard, although these were exceptional circumstances with coincidental outages. A sensitivity to the assumed forced outage rates is presented in the next section to assess the sensitivity of the projection to this key assumption.

Figure 5-28 shows installed capacity and projected unserved energy for the Alice Springs network.

Figure 5-28 Generator capacity reliability: Alice Springs unserved energy

Installed capacity (summer de-rated) Projected unserved energy

25 Territory Generation has provided forecast availability statistics for each of their portfolio generating units. These have been used in the first instance for each unit. IPP plant assume a similar forced outage rate.

26 Expected unserved energy is typically weighted between two peak demand outlooks, representing a peak demand coincident with extreme weather conditions and another with milder weather conditions. These reflect 10 per cent and 50 per cent probabilities of exceedance (POE 10 and POE 50), respectively, such that the peak demand will only be exceeded one in every 10 years and one in every two years, respectively.

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Source: AEMO

Figure 5-28 show that Alice Springs is expecting unserved energy well below the Standard. Again, only the most extreme generator outage timings risked breach of the 0.002 per cent standard.

5.4.2 Generator Response Reliability

Generation response reliability assesses the possibility of load shedding associated with insufficient spinning reserves to compensate for frequency disturbances. The duration of this form of UFLS is typically short, typically less than 20 minutes duration.

Analysis of the hourly market modelling simulations across 20 Monte Carlo iterations to identify the correlation of outages at the largest five generating units in Darwin-Katherine (Channel Island units 8 and 9, Weddell power station units 1 to 3) and the spinning reserves at the time of these outages.

UFLS is identified when spinning reserves do not cover the generation provided by the unit that fails at the time of failure.

This assessment is performed for two spinning reserve dispatch assessments, one with the minimum spinning reserve guidelines (25MW), and another with spinning reserves managed dynamically given the potential for generator contingencies.

UFLS occurs when active generating units have insufficient spare spinning reserves to compensate for frequency disturbances. In this assessment a focus on raise services is performed, to ensure the system is capable of enduring the largest generation contingency without incurring UFLS. This is referred to as generator response reliability.

This is most likely to occur in response to unplanned outages at the largest units in the system, the three Weddell generator units and Channel Island units 8 and 9. Insufficient spinning reserves to cover the lost generation at these units would likely lead to UFLS.

AEMO notes that the following System Control minimum spinning reserve guidelines exist to inform the dispatch of the Darwin-Katherine system27:

25 MW of Spinning Reserve at all times;

minimum of two Frame 6 machines must be dispatched at all times; and

27 Power and Water Corporation: System Secure Guidelines (September 2016)

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minimum of 15 MW of the Spinning Reserve requirement is to come from Frame 6 machines.

AEMO has modelled the Darwin-Katherine region with the minimum spinning reserves as outlined in the guidelines. Two methods were adopted within the market model:

Strict application of the above defined minimum spinning reserves; and application of the above defined minimum spinning reserves, as well as dynamic

consideration of raise services required to manage the single largest credible contingency at any given point. This approach mimics the anticipated discretion that System Control has used to maintain higher spinning reserves than are defined by the guidelines.

Error: Reference source not found demonstrates the modelled level of spinning reserve in the Darwin-Katherine system over the 2017-18 financial year using both of these approaches. Also shown is the actual spinning reserves observed in the Darwin-Katherine system since July 2015, and the minimum and maximum levels of spinning reserves required to be held.

The key conclusion is that the dynamic spinning reserve assessment is a much better reflection of the dispatch decisions being made by System Control on average. According to the Secure System Guidelines, the System Controller has discretion to exceed the minimum spinning reserves:

If adequate spinning reserve is achieved by ensuring, at a system level, a minimum amount of spinning reserve is maintained from units online with capability to ramp up quickly in response to any sudden loss of generation.

By directing the allocation of unit spinning reserve, to accommodate the perceived risk level of the power system or subnetwork at the time.

The modelling remains an approximation, as the financial and technical capabilities of each generator has only been provided at a relatively coarse level, which may lead to dispatch decisions that differ from those that may be expected in the real market dispatch. In particular, the granularity of the modelling may lead to different reserve provisions being required than what has been considered historically necessary by System Control.

Figure 5-29 Spinning reserve in the Darwin-Katherine system

Historical Spinning Reserve Forecast spinning reserves with alternate approaches

Source: AEMO

Application of the minimum spinning reserve targets exposes the system to UFLS events when generator outages exceed the level of spinning reserve. In this instance, insufficient rapid raise

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services are available at times to cover the sudden loss of generation, and load will need to be shed to compensate and re-balance the dispatch.

Examining Channel Island units 8 and 9, two of the largest units in the system, modelling results indicate that 74 per cent to 85 per cent of unplanned outages would have resulted in UFLS if only the minimum level of spinning reserves were available at the time of the outage.

The second generator response reliability approach therefore considers the dynamic generation raise reserve requirements to allow for the loss of the single largest outage contingency (consistent with assumptions and modelling approach used for the generator capacity reliability assessment). As shown in the previous figure, this leads to higher spinning reserves – approximately 40MW on average (or the size of the largest operating generating unit in Darwin-Katherine). If spinning reserves are maintained at this higher level, all generator outages did not trigger UFLS in the model.

Modelling Variations for Alice Springs

It is noted that the various of generation perfromance provide conflicting conclusions for Alice Springs. The N-X assessment is useful in providing a relatively simple gauge to assess system reliability. These indicate that there may be reliability concerns in the medium term.

The probabilistic modelling considers the balance of consumer demand and generation supply at a more granular level, and considers the probability of high consumer demand coinciding with coincident generator outages leading to insufficient generation available to meet demand. This probabilistic assessment therefore can reach different conclusions28 to the deterministic approaches.

Consolidation of these approaches may be beneficial in future reviews to improve the clarity of the generation adequacy assessment, as well as increasing the value in the insights obtained through the market modelling.

Modelling of the Alice Springs network will be a key issue for the 2016-17 power system review.

28 Changes in the mix of plant as well as variations in forced outage rates assumed when MRLs were calculated may lead to differences in the reliability assessments using a probabilistic approach versus deterministic methods. As such, the use of MRLs in the NEM has reduced in recent years, as the generation supply has evolved rapidly (and is no longer expected to remain static in future years).

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Figure 5-30 shows installed capacity and projected unserved energy for the Tennant Creek network.

Figure 5-30 Generator capacity reliability: Tennant Creek unserved energy

Installed capacity (summer de-rated) Projected unserved energy

Source: AEMO

Figure 5-30 shows Tennant Creek is expecting unserved energy well below the Standard.

The key outcomes are presented in Table 5-17 and are weighted across both POE 10 and POE 50 simulations29. Reliability in all regions is expected to be well in excess of the reliability standard. Figure 5-27 to Figure 5-30 reflect the neutral scenario in the table below.

Table 5-17 Projected unserved energy under neutral economic growth conditions

Darwin – Katherine Alice Springs Tennant Creek

2016-17 0.00000% 0.00000% 0.00000%

2017-18 0.00004% 0.00000% 0.00000%

2018-19 0.00001% 0.00000% 0.00000%

2019-20 0.00000% 0.00000% 0.00000%

2020-21 0.00001% 0.00006% 0.00000%

2021-22 0.00002% 0.00000% 0.00000%

2022-23 0.00002% 0.00000% 0.00000%

2023-24 0.00000% 0.00000% 0.00000%

2024-25 0.00002% 0.00000% 0.00000%

2025-26 0.00000% 0.00000% 0.00000%

Source: AEMO

29 The weighting of POE 10 and POE 50 is 69.6 per cent and 30.4 per cent, respectively. This is consistent with the weightings used in the NEM. The calculation method for determining these weighting factors is provided in the following document, and determining a Northern Territory-specific weighting factor may be preferable in future reviews.AEMO, Market Modelling Methodology and Input Assumptions, December 2016. Available at: http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NTNDP/2016/Dec/Market-Modelling-Methodology-And-Input-Assumptions.pdf

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http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NTNDP/2016/Dec/Market-Modelling-Methodology-And-Input-Assumptions.pdf

http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NTNDP/2016/Dec/Market-Modelling-Methodology-And-Input-Assumptions.pdf


5.4.2.1 Forced Outage Rate sensitivity

This assessment has been performed using reported forced outage rate statistics for each generation unit, as supplied by T-Gen. The forced outage rates are broadly in line with generating units in the NEM. Observed forced outage rates in the historical 2015-16 year were much higher, and it is important to consider the impact on power system reliability if units remained unavailable for higher proportions of time.

To understand the sensitivity of the outcomes to this assumption, AEMO modelled the forced outage rates observed in 2015-16. This results in expected failures approximately three times as frequently as in the primary assessment. If the poor generator reliability is consistent with that observed in 2015-16, there is a risk of supply shortfalls in Darwin-Katherine due to coincident outages at times of high demand.

As illustrated by Figure 5-31 using these higher forced outage rates the expected unserved energy averaged across the modelling exceeds the 0.002 per cent standard as a weighted average in every year of the assessment.

Figure 5-31 Generator capacity reliability for Darwin-Katherine with historical forced outage rates

Source: AEMO

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6. Fuel Supply

This chapter provides analysis on the adequacy of fuel supply to the Territory’s regulated power systems. In the Territory, the main source of fuel is gas, with diesel used as a last-resort backup in the event of prolonged gas shortages.

The chapter reviews:

The adequacy of fuel resources and fuel transport for electricity generation for the medium and long term, including discussion of any significant risk to continuity of supply;

provides advice on the security of supply arrangements; and

reviews potential developments in the area of fuel resources.

The review methodology of the 2015-16 report is broadly consistent with the previous year’s report.

6.1 Adequacy of Northern Territory Gas Supply

6.1.1 T-Gen’s Gas Requirement

T-Gen’s gas demand for 2015-16 was approximately 21 PJ30 noting around 85 per cent of all gas consumed in the regulated systems was in the Darwin-Katherine system. PWC’s gas sales to other parties and other generation requirements resulted in a total Territory 2015-16 gas usage of approximately 22 PJ representing a small decrease in demand compared to 2014-15.

Gas requirements for electricity are forecast to have flat to slightly negative growth during the next five years. Increased efficiency from modern generation facilities and new solar generation are offsetting small increases in power demand. Increased competition from third-party generation may also reduce the Territory’s gas requirement over the medium to long term.

6.1.2 PWC Gas Supply: annual demand

PWC has a contract to purchase gas from ENI’s offshore Blacktip gas field in the Bonaparte Basin via the Wadeye plant. The contract runs for 25 years. It commenced in 2009 for the supply of up to 740 PJ of gas over the life of the project. PWC has the possibility to take additional gas if required.

The annual contract quantities from Blacktip increase over time to allow for growth in the Territory’s demand.

6.1.3 PWC Gas Supply: maximum daily quantity

There are currently no issues with PWC meeting its daily maximum demand. It is noted that PWC’s daily maximum demand is expected to grow faster than the growth in annual demand. While no immediate issues with meeting maximum demand, the Commission will seek to understand what the

30 Demand includes gas used in Territory Generation’s power purchase agreements.

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impact of supplying gas to the eastern states will have on meeting domestic maximum demand requirements.

6.1.4 Gas Transportation Capacity

The transportation capacity of the Bonaparte Pipeline and the Ban Ban Springs to Darwin section of the Amadeus pipeline is over 100 TJ/d31. Figure 6-32 is a map of the Territory Gas Transportation pipeline infrastructure. PWC has entered into long term transportation agreements with the owners of the Bonaparte and Amadeus gas pipelines to transport Blacktip gas to its various power station delivery points in the Territory.

31 PWC transportation assessment, Figure 1

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Figure 6-32 Northern Territory gas infrastructure

Source: PWC

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6.2 Security of Gas Supply

Gas supply to the Territory is assessed to have ‘n-1’ redundancy for a short to medium period of time. An ‘n-1’ system redundancy has spare supply capability that is sufficient to supply 100 per cent of the Territory’s gas requirement, should the primary source of gas supply fail.

In theory both Blacktip and Darwin LNG can individually supply 100 per cent of the Territory’s gas requirement. However, it is important to note there are some limitations to the Darwin LNG back-up arrangement relating to restrictions in total volume across the year and pressure issues. New supply from the Dingo gas field and potential additional supply from Mereenie/Palm Valley is likely to reduce these risk.

As detailed below in the Commission’s considerations of pipeline line pack, Amadeus basin gas and diesel back-up generation provides additional energy support to the Territory, however these measures are not capable of replacing 100 percent of Territory’s energy requirement in the event of a simultaneous Blacktip and Darwin LNG outage which extends for a small period. Alternate energy supply is expected to last for less than a day.

The commencement of the Inpex LNG back-up supply arrangement (in approximately mid-2018) will increase Darwin gas system security to ‘n-2’ until 2022. PWC’s Darwin LNG back-up arrangement expires in 2022 (unless a new extension agreement can be agreed by the parties).

6.2.1 Blacktip Gas Field

6.2.1.1 Redundancy of Blacktip Infrastructure

The Blacktip gas field consists of two offshore wells with an unmanned and remotely operated well head platform. The onshore plant consists of three export compressors, simple separation and dehydration facilities and utilities such as power generation. This type of facility is similar to other upstream gas projects in eastern Australia like those in the Otway basin which supplies gas to the Victorian domestic market. Generally, unmanned offshore facilities will have a lower level of reliability than manned or onshore facilities. The additional time taken to fly out to an unmanned platform and assess the nature of any production issues will increase the time of a supply interruption.

The two development wells provide some level of field deliverability redundancy. The onshore gas plant at Wadeye has three export compressors, which are required to be fully operational to produce gas at maximum production rates. Where a gas plant has an extra unit on standby for each major processing element (that is compression, dehydration, liquids separation, utilities etc.), the gas plant is referred to as having full ‘n-1’ redundancy. At maximum production rates (approx. 110 – 120 TJ/d), the Wadeye facility does not have full redundancy for periods of planned maintenance activity or an unplanned trip of major processing elements of the gas plant. Plant utilities such as steam and power are often a source of production issues for a plant like the Wadeye facility and an interruption to power was the cause of the 11 September 2014 incident.

PWC’s maximum day requirement for gas is currently significantly below the maximum capacity of the Blacktip gas plant. The amount of redundant plant capacity (created by current low levels of demand) will decrease over time as the rate of maximum day demand increase. This will jump to a new level when PWC’s supply to eastern Australia commences in 2019.

Without full ‘n-1’ redundancy on all major elements of plant processing capacity, there in an increased risk of minor or major shortfalls during periods of plant failure coinciding with maximum gas demand. Given PWC’s strong back-up arrangements, this is not an area of concern but should be

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noted and may involve a greater level of management of PWC’s daily gas supplies in the medium term.

6.2.1.2 Blacktip Planned and Unplanned Maintenance

Typical to other gas sales agreements, there are limits on the duration of planned and unplanned maintenance interruptions of gas supply from Blacktip facilities each contract year. Importantly, there are also restrictions on the number of days in a row for a single interruption. The duration and scale of any Blacktip supply shortfall will determine whether PWC is required to call upon its back-up gas arrangements. The permitted periods of planned and unplanned maintenance and maximum number of days of continuous interruption are well within PWC’s back-up capabilities from Darwin LNG.

6.2.1.3 Blacktip Reserves

Gas reserves and well deliverability are critical elements of gas supply security. Field performance should be regularly monitored over time. Blacktip’s current 1P32 reserves are sufficient to satisfy its long term contractual obligations to PWC. Blacktip is at an early stage of its producing life, having produced for only seven years of a 25 year supply term to PWC. It is recommended that reserves, well deliverability and levels of reservoir water production be monitored at regular intervals over the life of the project.

While there are no current indications of Blacktip reserve or deliverability issues and ongoing risks are low given 1P reserves are sufficient to satisfy ENI’s contractual obligations to PWC, a major failure of Blacktip reserves/deliverability would be classified as a catastrophic event and lead to a wide scale gas shortage and/or material cost implications for the Territory. It is recommended that PWC or the Territory government assess contingency plans in the event of a major failure of Blacktip reserves, especially since a significant quantity of uncontracted reserves in the Amadeus Basin are likely to be supplied to customers in eastern Australia when Jemena’s Northern Gas Pipeline (NGP) is interconnected with eastern Australia.

6.2.2 Amadeus Basin Gas

6.2.2.1 Mereenie/Palm Valley

The development of the Blacktip field created gas-on-gas competition in the Territory for the first time. The large quantities of Blacktip gas supply and the unutilised productive capability of Amadeus Basin gas created an oversupply in the Territory. This created a competitive gas market for customers and put downward price pressure for new gas supply contracts. It is currently estimated there is up to 100 PJ of conventional proven and probable tail gas reserves remaining in the Amadeus Basin, most of these in the Mereenie gas field.

The commencement of Jemena’s NGP from late 2018 / early 2019 will open up new gas supply opportunities for Mereenie/Palm Valley gas, which could result in large quantities of the uncontracted Amadeus Basin gas reserves being supplied to eastern Australia. Jemena is likely to transform the Territory gas market from one of excess conventional gas supply capabilities to limited quantities of uncontracted conventional gas reserves from Blacktip and the Amadeus Basin.

32 1P reserves denotes proved reserves under the Petroleum Resource Management System (PRMS), developed by the American society of petroleum engineers to classify oil and gas resources. 1P reserves have a 90% confidence level of being produced over the life of the asset.

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While PWC’s arrangements with Darwin LNG and Inpex LNG will remain PWC’s main source of back-up gas, the likely reduction in Amadeus Basin’s uncontracted gas reserves from commencement of the NGP will reduce gas supply security in the Territory, as the availability of additional supply and/or back-up gas supply from the Amadeus Basin reduces.

6.2.2.2 Dingo

In September 2013, PWC entered into a new gas sales agreement to develop the Dingo gas field, located 60km south of Alice Springs. PWC’s initial supply tranche is around 15 PJ over a ten year term from the Dingo gas field, with options to increase supply up to 31 PJ of gas over 20 year supply period if sufficient reserves are available33. Gas supply from the Dingo gas field to PWC commenced in April 2015. Dingo gas is connected into the pipeline transmission system at Brewer estate, 20km south of Alice Springs. The development of Dingo provides an additional supply option for PWC and will also improve the efficiency of the new Owen Springs Power Station. Dingo gas is “leaner” (that is, it contains lower levels of LPGs) compared to “rich” shale gas from Mereenie. Modern gas engines run more efficiently utilising leaner shale gas compared to rich shale gas streams.

6.2.3 LNG Back-up Supply

PWC’s back-up supply arrangements with Darwin LNG and Inpex LNG are not considered traditional firm supply agreements, as their respective LNG production would take precedence over supply to PWC. The back-up supply arrangements also have a long lead time before back-up supply can commence – 24 hours to respond to a request then 48 hours for supply to commence. This period to commence back-up supply is too long to assist a significant emergency response and PWC relies on a reasonable endeavours obligation with Darwin LNG and Inpex LNG to commence earlier back-up supply. Given the scale of the LNG operations and the importance of gas supply to the Territory, it is likely that Darwin LNG or Inpex LNG would supply gas to PWC as soon as possible when requested.

6.2.3.1 Darwin LNG

PWC has an existing back-up arrangement with Darwin LNG’s Wickham Point facility. This arrangement will continue until the end of 2022. Assuming a northern maximum demand of 65 TJ/d (Darwin-Katherine region), the existing Darwin LNG back-up arrangement could supply the northern region for five to six weeks (or longer periods during low demand). PWC has previously utilised Darwin LNG back-up supply during periods of planned and unplanned interruption of Blacktip production. At the time of the 11 September 2014 incident, Darwin LNG was undergoing planned maintenance and therefore not immediately available at the time when supply from Blacktip was interrupted. Other than the 11 September 2014 incident, PWC’s Darwin LNG back-up arrangement has been proven to be effective and is currently PWC’s main mechanism to manage supply shortfalls from Blacktip.

The northern region of Darwin-Katherine (where the majority of generation is located) can be supplied using Darwin LNG back-up gas. Pipeline pressures in the Amadeus pipeline may not be sufficient to transport Darwin LNG back-up gas south of Tennant Creek. Where there is a partial supply from Blacktip, Blacktip gas would continue to supply southern demand. Where there is a total loss of Blacktip gas, the southern region would be supplied through a combination of pipeline line pack, Darwin LNG (if pipeline pressure is suitable), Dingo gas, and diesel generation. In an extended outage, additional gas from the Amadeus basin is likely to be required to supply the southern region.

33 Magellan press release, 12 September 2013

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6.2.3.2 Inpex LNG

PWC has executed an agreement for a second back-up supply with Inpex LNG. This arrangement will commence upon operation of Inpex’s LNG plant in mid-2018 for a period of 15 years. This second PWC back-up arrangement will greatly improve security of gas supply to the Territory, not only in duration of northern back-up supply capability (by doubling the period of coverage to at least 13 weeks), but also by managing the circumstance of a simultaneous interruption of gas supply from Blacktip and Darwin LNG. Inpex’s maximum delivery pressure is lower than Darwin LNG and is likely to have limited ability to supply gas further south than Darwin. For the 2016-17 power system review the Commission will seek further detail on the interaction between Darwin LNG and Inpex LNG jointly providing back-up supply and the ability for Inpex LNG to provide back-up gas to the Territory’s gas requirements further south of Darwin.

6.2.4 Gas Transportation

6.2.4.1 Pipeline Failure

Neither the Bonaparte pipeline nor the Amadeus pipeline have operating mid-line pipeline compressor stations. The lack of an operating mid-line compressor station reduces the risk of a transmission interruption.

Pipeline rupture of the Bonaparte or Amadeus pipeline is likely to cause some level of gas interruption to electricity generation in the Territory. The location of the pipeline rupture would determine the extent of gas interruption, however this type of event is rare and even a major rupture is likely to be rectified within 5-10 weeks. Minor pipeline leaks are likely to be repaired within 24 hours. The gas transportation system does not have full redundancy in the event of a major rupture of the Amadeus gas pipeline and the location of the rupture would impact the ability of supply contingency solutions to cover a transmission failure.

6.2.4.2 Pipeline Line Pack

Spare gas stored in transmission pipelines is referred to as pipeline line pack. Spare pipeline line pack is considered a small and short term supplement to the main gas contingency strategy. The amount of line pack that can be used to supplement gas demand during a shortfall of Blacktip production depends on:

the prevailing pipeline operating pressure. The quantity of spare pipeline line pack is increased at higher pipeline operating pressures; and

pipeline throughput and the amount of spare or unutilised firm transportation capacity. Gas transmission pipelines which are short, or transport gas close to their maximum design capacity have virtually no spare pipeline line pack. Gas pipelines that are long and have large quantities of unutilised capacity can have material quantities of spare line pack to supplement demand during periods of gas shortfall.

PWC has provided high level estimates of available line pack which can be taken from the relevant pipelines before generation is restricted:

• Bonaparte Gas Pipeline – up to 35 TJ;

• Amadeus Gas Pipeline (Ban Ban Springs to Darwin section) – less than 5 TJ;

• Amadeus Gas Pipeline (Ban Ban Springs to Alice Springs) – up to 100 TJ;

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• Wickham Point Pipeline (Darwin LNG to Channel Island) – up to 1 TJ; and

• Palm Valley to Alice Springs Pipeline – less than 4 TJ.

It is important to note however, the above estimates of spare pipeline line pack in the Amadeus Gas Pipeline will significantly change with commencement of Jemena’s Northern Gas Pipeline. The direction of gas flows in the Amadeus Gas Pipeline will change upon commencement of the NGP and hence the availability of line pack in this pipeline.

The change in the direction of pipeline flow from south to north in the Amadeus Gas Pipeline from Mereenie (i.e. gas now flows from Mereenie to Ban Ban Springs), reduces spare pipeline line pack in the Amadeus Gas Pipeline to support the Alice Springs region in the event of a Blacktip supply failure, however this is more than offset by new supply from the Dingo gas field which adds to supply security to this region.

The northern section of the Amadeus pipeline from Ban Ban Springs to Darwin has limited spare line pack because of its short distance and high flow rates. The Bonaparte gas pipeline represents the largest source of spare line pack for the northern region, however at maximum demand rates Bonaparte gas pipeline’s spare line pack would maintain Darwin-Katherine generation for less than one day if gas production ceased from Blacktip. The change in Amadeus Gas Pipeline flow from Mereenie to Darwin will provide some level of increased line pack support (from the Ban Ban Springs to Alice Springs section of the Amadeus gas pipeline) for the Darwin-Katherine region. Spare pipeline line pack is considered a small and short-term supplement to the main gas contingency strategy.

6.2.5 Diesel Backup

PWC has a number of facilities capable of using diesel as a last resort if no sources of back-up gas or spare line pack are available. Katherine, Tennant Creek, Ron Goodin and Owen Springs power stations have duel fuel (i.e. gas and diesel) generation capabilities. Channel Island has some gas generators that can be converted to diesel in 24-48 hours. In some gas supply short fall scenarios, 24 to 48 hours could be too long to assist continuous generation at Channel Island and Darwin’s only fuel contingency would be back-up supply by Darwin LNG or Inpex.

PWC has substantial diesel storage capacity at all its dual fired facilities, although the new diesel tanks at Owen Springs power station have a smaller diesel storage capacity than the tanks at the old Ron Goodwin power station. Ron Goodin power station is being phased out by the Owen Springs power station upgrade, which is expected to be completed in late 2017.

The operational inventory of diesel storage varies, depending on the location and availability of back-up gas supply. Diesel back-up is the last major source of fuel after all gas supply contingencies have been exhausted. While stand-by diesel stocks incur a significant cost, they remain a critical part of Territory power system security, particularly south of the Darwin-Katherine system.

6.2.6 Contingency Analysis – Failure of Blacktip or Gas Transportation

An analysis of the contingency arrangements for a major and minor failure of Blacktip supply and gas transportation capacity is detailed in Table 6-18.

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Table 6-18 Gas contingency analysis

Incident Event Contingency/Outcome

Partial loss of Blacktip supply,

less than 10 days.

Minor plant failure or shutdown

northern supply from Darwin LNG and/or Inpex LNG. southern supply from Blacktip. no impact, within normal contingency.

Partial loss of Blacktip supply for more than 5

weeks.

Major failure of plant/equipment

requiring extended period of repair.

northern supply from Darwin LNG and/or Inpex LNG, additional gas maybe required.

southern supply from Blacktip. outside normal contingency and may require additional gas

purchases from Amadeus/Darwin LNG/Inpex LNG.

Full loss of Blacktip supply for less than 10

days.

Significant failure of plant or extended

maintenance.

northern supply from Darwin LNG and/or Inpex LNG southern supply from pipeline Darwin LNG (subject to

sufficient pipeline pressures), northern LNG back-up, Amadeus gas or diesel.

no impact, within normal contingency, unless Amadeus gas required.

Full loss of Blacktip for more

than 5 weeks.

Catastrophic failure of field or plant, reserve failure, fire/explosion.

northern supply from Darwin LNG or Inpex LNG, additional gas required.

southern supply from additional Darwin LNG (subject to sufficient pipeline pressures), Amadeus Basin gas or diesel.

outside normal contingency and requires additional gas purchases from Amadeus/Darwin LNG/Inpex LNG. Large additional costs, but gas should be available from Darwin LNG or Inpex to satisfy PWC’s full gas requirements, but this cannot be guaranteed.

Pipeline Rupture Minor Rupture – less than 24 hrs.

Blacktip, Darwin LNG or Inpex LNG back-up, pipeline line pack where rupture doesn’t prevent gas supply.

diesel where rupture prevents gas supply no impact, within normal contingency.

Pipeline Rupture Major Rupture – more than 5 weeks

Blacktip, Darwin LNG or Inpex LNG back-up, pipeline line pack where rupture doesn’t prevent gas supply.

diesel where rupture prevents gas supply possibly outside normal contingency and may require

additional gas purchases from Amadeus/Darwin LNG/Inpex LNG.

6.3 Potential Developments in Territory Fuel Resources

There have been a number of upstream parties exploring for new oil and gas opportunities in the Territory, however the recent period of low oil price has reduced the level of exploration activity for new gas resources. Onshore activity tends to be focused on unconventional gas exploration, mostly shale gas opportunities and offshore activity on new conventional resources.

Onshore unconventional developments are more likely to provide new domestic supply opportunities compared to offshore exploration because:

onshore developments can support small scale initial developments with incremental expansion, while offshore developments require large markets (such as LNG supply) to justify the large capital cost of bringing gas onshore; and

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generally only large producers participate in offshore exploration due to the large costs - these producers tend to focus on big scale LNG projects rather than smaller domestic supply projects.

While an offshore project can supply gas to a Darwin LNG project and domestic supply opportunities concurrently, history has shown that large companies tend to be singularly focused on LNG projects (such as, ConocoPhillips, and Inpex) and not domestic markets.

The backfill of ConocoPhillips’ Darwin LNG plant after depletion of Bayu-Undan gas reserves around 2022-23 or the potential Darwin LNG plant expansion is a large market opportunity for new sources of Territory gas. ConocoPhillips is currently focussing on new Browse basin and Timor Sea gas to satisfy its Darwin LNG project, although onshore unconventional gas could also supply this opportunity. Jemena’s NGP provides other domestic market opportunities for Territory gas which should also provide support for further exploration.

In summary, there are a number of potential new sources of gas supply in the Territory, although all need further exploration and appraisal to establish their technical and commercial viability. Most of these new supply opportunities are from onshore unconventional gas exploration/appraisal such as tight gas in the Amadeus Basin or shale gas in the northern basins of the Territory. An offshore tie-back to the existing Blacktip field from other resources in the Bonaparte basin could also provide new domestic supply opportunities.

6.3.1 Onshore Exploration Activity

The focus of onshore Territory exploration and appraisal activity over recent years has been unconventional shale gas. Santos has previously been the most active gas major, farming in to the McArthur, Georgina and Pedrika basins, although in recent times has substantially reduced its activity due to financial constraints. Central Petroleum has acquired a major interest in the Mereenie gas field, which has the potential for major new tight gas opportunities. Macquarie Bank is seeking to take over Central Petroleum and it may provide a new source of capital to accelerate appraisal and development of tight gas in the Amadeus Basin.

The current low oil price is also reducing the level of exploration and appraisal activity for onshore unconventional gas in the Territory. Mobilising rigs and other drilling equipment to isolated areas in the Territory is time consuming and expensive. Many areas of exploration are not accessible in the wet season which increases the time to explore and appraise permits. While the fundamentals for additional gas supply to eastern Australia from the Territory supports further reserve development activity, the high exploration costs and long lead times for commercialisation will restrict the amount of capital oil and gas companies can allocate to Territory exploration activities, especially in the current low oil price environment.

The conclusion is that onshore unconventional exploration and appraisal success in the Territory is likely to take many years, with new large-scale unconventional onshore reserves that are needed to support the gas pipeline to the eastern states is at best, unlikely to be available prior to the early part of the next decade.

6.3.2 New Long-Term Gas Supply

The time required to explore, appraise and develop new gas supply tends to take much longer than expected. It is possible that new large scale onshore unconventional gas supply in the Territory could take over 10 years to materialise. PWC’s existing gas sale agreement with Blacktip is not due to expire until around 2033. However, it would be prudent to give consideration new gas supply after the end of the Blacktip contract.

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It is recommended the Territory develop a gas procurement strategy for new supply post the end of the Blacktip gas field and that it include an assessment of the risks for an early end of the Blacktip gas sales agreement. It is unclear whether procurement of new gas supply will be undertaken by PWC or T-Gen and therefore the party that will engage the market for new gas supply should also be considered by the Territory Government.

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7. Review of Transmission Networks and Planning

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7.1 Northern Territory Power Systems

As illustrated by Figure 7-33, PWC operates three electricity power systems in the Territory; Darwin-Katherine; Alice Springs; and Tennant Creek. The three power systems are unconnected and operated separately by PWC.

Figure 7-33 Overview of PWC operated Northern Territory power systems

Source: PWC

PWC’s electrical networks operate at transmission voltages of 132 kV and 66 kV and, distribution reticulation at 22 kV and 11 kV.

7.1.1 Darwin-Katherine Power System

This is the largest power system in the Territory. It supplies Darwin city, Palmerston, suburbs and surrounding areas of Darwin, the township of Katherine and its surrounding rural areas. Power stations are located at Channel Island, Weddell, Pine Creek and Katherine. Figure 7-34 illustrates the

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Darwin–Katherine power system

Alice Springs power system

Tennant Creek power system


Darwin-Katherine power system, with the lines in red, that is, lines from Katherine to Channel Island and Channel Island to Hudson Creek are the only transmission lines in the Territory34.

The total generation is over 500 MW and the fuel type of the generation units is made up of dual fuel (gas/diesel), gas only, waste heat steam and land fill gas. The operational maximum demand in 2015-16 was 293 MW.

A 132 kV double circuit overhead transmission line (about 300 km) connects Channel Island power station to Hudson Creek terminal station, which serves Darwin area. This system has a single 132 kV overhead transmission line (~300 km) from Channel Island to Katherine with three connection points in between at Manton, Bachelor and Pine Creek.

7.1.2 Alice Springs Power System

This is the second largest power system in the Territory. It supplies the township of Alice Springs and surrounding rural areas from the Ron Goodin, Owen Springs and Brewer and Uterne solar power stations.

The total generation is 90 MW and the fuel type of the generation units is made up of dual fuel (gas/diesel), diesel only, gas only and solar PV. The operational maximum demand in 2015-16 was 53 MW. The highest voltage of the network is 66 kV.

7.1.3 Tennant Creek Power System

This system supplies the township of Tennant Creek and surrounding rural areas from its centrally located power station. The total generation is 17 MW and the fuel type of the generation units is made up of diesel and gas. The operational maximum demand in 2015–16 was 6.8 MW. The highest voltage of the network is 22 kV.

7.1.4 Scope of Transmission Review

The review of the transmission network adequacy focuses on the Darwin–Katherine and Alice Springs power systems, as Tennant Creek network does not include any transmission assets.

34 As defined in the Network Technical Code and Planning Criteria. Lines at 132kV and 66kV would not normally be classified as transmission assets under the NEM.

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Figure 7-34 Single line diagram of Darwin–Katherine transmission network

Mary River

Channel Island

Hudson Creek

Weddell

Woolner

Strangways

Palmerston

Humpty Doo

Marrakai

Berrimah

Casuarina

Frances Bay

City Zone

Centre Yard

Manton

Batchelor

Pine Creek

Katherine

Union Reef

Cosmo Howley

G

G

G

G

Total 129 MW

Katherine generation:3x7.4 MW units1x12.5 MW unit

Pine Creek generation:2x9.64 MW units1x7.31 MW unit1x1.1 MW unit

Archer

Weddell generation:3x43 MW units

Channel Island generation:2x42 MW units5x31.6 MW units1x36 MW unit1x32 MW unit

Leanyer

Wishart

Service date 2017/18

Legend: 132 kV transmission line 66 kV transmission line New line in construction (66 kV)

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7.2 Transmission Network Adequacy and Reliability

7.2.1 Transmission Line Utilisation

The transmission voltages are lower than in other jurisdictions but the assets fulfil the same functional purpose.

PWC has a program of monitoring the MD on each 66 kV transmission circuit and predicting the growth of that over the coming 10 years. The utilisations predicted are typically quite low with 33 per cent of circuits loaded below 22 per cent and only 33 per cent of circuits loaded above 40 per cent under non-contingency circumstances during the 2026-27 year.

PWC has considered the loading of 66 kV circuits for a number of credible circuit outages. The data for the contingencies considered shows that all circuits operate within their capability. The Strangways to Weddell lines are the lines that operate close to their rating under contingency circumstances.

Based on limiting the normal and contingency loadings to approximately 100 per cent, PWC has devised a number of proposed network augmentations. These augmentations are shown on the 10-year master plan. The Commission considers that over the past few years, PWC has made significant improvements to its 10-year master plan.

The Darwin-Katherine system 10-year master plan shows the following key augmentations that address concerns raised in previous reviews. PWC has also reported good progress in implementing these plans:

establish the Wishart ZSS – stage 1 complete;

establish a high capacity (120 MVA) 66kV Hudson Creek to Wishart circuit – after further analysis PWC determined that it is better to redirect a 66 kV line; and

establish a Palmerston to Archer 66kV circuit – business case approved and contract awarded.

The Commission considers these changes to add considerable flexibility in the operation of the 66kV network in the event that one key circuit is not available for service.

The NMP acknowledges that there is significant uncertainty about the quantity and timing of additional demand at the proposed development of East Arm industrial area in Darwin. However, PWC is engaging with the developers and current indications are that significant new load will not come on until 2019-20. PWC has plans in place for the possibility that this increased demand comes to fruition quicker than expected.

The Commission notes that section 4.1.1 of the NMP says:

‘In addition, at the discretion of Power Networks, certain high impact but low risk failures such as the failure of a single ZZS High Voltage (HV) busbar, or the failure of both circuits of a double circuit double circuit line, shall be considered as second contingency events.’

It seems likely to the Commission that loss of the double circuit line from Channel Island to Hudson Creek is treated as a double contingency event. An outage of these lines will certainly lead to a loss of supply to Darwin city and possibly a system black of the Darwin-Katherine system.

Consistent with the Commission’s concerns expressed in previous power system reviews, PWC has completed extensive work to reduce the likelihood of an outage of this transmission line. Works completed include:

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replacement of the six unreliable circuit breakers at the Hudson Creek end of the line;

the transmission line electrical protection, circuit breaker failure protection replaced and modernised;

circuit breaker fail and auto-reclose relays replaced;

new earth bonding has been installed between towers and overhead earth wires on both CIPS – HCTS 132kV transmission lines reducing the likelihood of a lightning strike on one circuit causing an outage of both circuits;

transmission tower earth grid testing has been completed and no shortcomings identified; and

the Elizabeth River Crossing portion of the circuit is being upgraded to reduce the expected duration of a circuit outage that could result from a severe cyclone.

Now that remedial work on the 132kV line from Channel Island to Hudson Creek has been substantially completed it may be reasonable to consider a double circuit failure as a second contingency event. In the NEM failure of a double circuit line similar to this one, it would likely be declared a credible event during lightning storms.

PWC has assessed the adequacy of its transmission circuits based on their thermal capability for a small number of contingency events. PWC acknowledge in the NMP that this assessment is indicative because other considerations such as voltage drop and transient stability can reduce the capability of transmission lines. The Commission’s ongoing recommendation is that PWC should check these considerations, and report the results of those investigations in the next NMP. This would require an accurate power system model.

7.2.2 Transmission Line Utilisation

PWC’s latest NMP presents forecast maximum power flow on each of the 132 kV and 66 kV transmission circuits at the time of maximum demand for the period from 2016–17 to 2026–27. It presents: maximum power flow on each of these circuits with all transmission circuits in service (system

normal loading); and maximum power flow on each of these circuits following any single transmission circuit outage

(post-contingent loading).

PWC compared the system normal loadings with their ‘normal rating’ of the transmission circuit and post-contingent loadings with their ‘contingency rating’, which is higher than the normal rating. PWC’s application of rating of transmission circuit is similar to the approach in the NEM. A normal rating is applied continuously under pre-contingent conditions and a higher rating is applied for a limited period under post-contingency conditions.

System normal and post-contingent maximum power flow of all 132 kV transmission circuits were forecasted to remain within the respective thermal capacity for the period 2016–17 to 2026–27. System normal and post-contingent power flow on Darwin-Hudsons Creek 132 kV transmission circuits were forecasted to be 41 per cent of normal rating and 77 per cent of contingency rating respectively for the period 2016–17 to 2026–27. System normal maximum power flow on the Channel Island–Katherine 132 kV circuit was forecasted to be 19 per cent of normal rating for the period 2016–17 to 2026-27.

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System normal and post-contingent power flow of all 66 kV transmission lines, except Weddell-Strangways 66 kV line, are within their normal and contingency ratings respectively to meet the forecast maximum demand for the period 2016–17 to 2026–27. In 2017–18, power flow on the Weddell–Strangways 66 kV line is forecasted to exceed its contingency rating by 2 per cent in the event of an outage of Hudson Creek–Palmerston 66 kV line. Load reduction may be required at Palmerston, Strangways, Humpty Doo, Maracay and/or Mary River zone substations to prevent post–contingent overload. Construction of new 66 kV line between Archer and Palmerston is in progress with target service date in 2018–19. Following service of this new line, no overload is forecasted on Weddell–Strangways 66 kV line from 2018–19.

7.2.3 Terminal Station and Zone Substation Transformer Utilisation

In Darwin-Katherine system, terminal stations refer to locations that facilitate transformation from 132 kV to 66 kV. Terminal stations are located at Hudson Creek and Pine Creek.

Forecast maximum loading on 132/66 kV transformers at these terminal stations are given for the period 2016-17 to 2020-21. The system normal loading and post-contingent loading (N-1) forecast to remain within their normal and contingency cyclic ratings, respectively.

ZSS deliver supply from 132 kV or 66 kV transmission network to 22 kV or 11 kV distribution network. Forecast loading on transformers at ZSSs is provided for the period 2016-17 to 2020-21. The system normal loading and post-contingent loading of transformers in all ZSSs, except three ZSSs, forecast to remain within their normal and contingency cyclic ratings, respectively.

Palmerston ZSS 66/11 kV transformer load is forecasted to exceed its contingency cyclic rating in 2016-17 and a project is in progress for installation of an additional 66/11 kV transformer at Palmerston with a service date in 2017-18. In 2016-17 to manage overload at Palmerston, PWC has a plan to transfer the excess load at Palmerston ZSS to Berrimah and Casuarina ZSSs.

Archer and Strangways ZSS transformer maximum post-contingency loading is forecasted to exceed their contingency cyclic ratings following an outage of a transformer at these ZSSs. The excess load at these substations is forecasted as 10.6 MVA in 2016-17 and it increases to 25.5 MVA in 2020-21.

Action needs to be taken during system normal conditions to ensure secure operation. PWC has a plan to transfer load from these two ZSSs to Palmerston 66/22 kV ZSS during peak demand periods. Palmerston ZSS will have spare capacity (following installation of a third transformer in 2017-18) to accommodate transferred load from Archer and Strangways ZSS for the period from 2017-18 to 2020-21. In 2016-17 (prior to installation of a third transformer), PWC need to transfer the load from Palmerston ZSS to Berrimah and Casuarina ZSSs before transferring excess load from Archer and Strangways.

PWC’s work to install an additional transformer at Palmerston ZSS and action to transfer excess overload at Archer and Strangways ZSS demonstrates all transformer loading within their respective thermal ratings.

7.2.4 Fault Levels

AEMO reviewed the 132 kV and 66 kV fault levels presented in the NMP against the circuit breaker interruption capability, which were provided separately by PWC. AEMO’s assessment has confirmed that maximum fault levels are within the circuit breaker interruption capability.

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7.2.5 Voltage Control Management

The current NMP does not provide information regarding voltage and reactive power control. AEMO separately discussed voltage/reactive power control practices with PWC. In summary: Voltage control in the Darwin area is managed with reactive power support from generators at

Channel Island and Weddell generating units and capacitor banks located at number of ZSSs.

During periods of high demand in the Pine Creek and the Katherine area, reactive power support is provided by the capacitor banks at Katherine ZSS.

Katherine ZSS is connected at the end of 300 km 132 kV transmission line. It is understood that at times of low demand periods Katherine ZSS experiences high voltage. These high voltage scenarios are controlled with Pine Creek and or Katherine generating units when instructed.

7.2.6 Power System Stability

The current NMP does not provide power system stability-related information. PWC separately provided system incident reports. Event history shows the 132 kV line between Manton and Katherine has tripped several times and resulted in an island formation of Katherine or Katherine-Pine Creek. The line remained within the required availability range but the incident record shows: during and following the island formation of Katherine or Katherine and Pine Creek the Darwin

power system remained stable, with no lost load;

when there was sufficient spinning reserve, frequency was controlled without any load shedding. At times of insufficient spinning reserve, UFLS scheme has shed load to maintain frequency within the limits (resulting in the loss of up to 27 MW of customer load for 36 minutes);

Katherine ZSS experienced a black out following formation of island when no generators were in service at Katherine; and

Katherine ZSS load restored with reconnection of the Channel Island-Katherine 132 kV line.

7.2.7 Power System Stability with Solar PV Penetration

At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, whichresults in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, whichresults in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, whichresults in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, whichresults in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels

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synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, whichresults in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. At minimum demand levels synchronous generation is normally reduced, which results in less inertia and reactive support. Error: Reference source not found illustrates forecast minimum demand with rooftop PV penetration in theDarwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems. illustrates forecast minimum demand with rooftop PV penetration in the Darwin-Katherine and Alice Springs systems.

Rooftop PV is forecasted with no impact on the minimum demand in the Darwin-Katherine and Tennant Creek systems for the next 10 years. Alice Springs system minimum demand is predicted to decrease from 7.6 MW in 2016–17 to 2.9 MW in 2025–26. This is likely to reduce the number of synchronous generators required in service.

Figure 7-35 Minimum demand forecast

60

70

80

90

100

2016/17 2020/21 2025/26

Min

imum

dem

and

(MW

)

Year

Darwin-Katherine system

4

6

8

10

12

2016/17 2020/21 2025/26

Min

imum

dem

and

(MW

)

Year

Alice Spring system

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Source: AEMO

Currently there are no large scale solar PV generation connection proposals in the PWC’s transmission network. However, if large scale solar PV generation were to be added, it may reduce the number of synchronous generators in service. The reduced number synchronous generators could affect power system stability, rate of change of frequency and system strength for secure operation of the network.

7.2.8 Transmission Network Performance

The current NMP includes key indicators to measure the reliability performance of the PWC transmission network. These indicators are:

system average circuit outage duration index (ACOD), which indicates the average duration of circuit outages experienced by the PWC transmission network;

frequency of circuit outage index (FCO), which indicates the number of circuit outages experienced by PWC transmission network;

system average transformer outage duration index (ATOD), which indicates the average duration of circuit outages experienced by the PWC transmission network; and

FTO index, which indicates the number of transformer outages experienced by PWC transmission network.

The performance indicators and targets do not apply in Alice Springs and Tennant Creek.

For the Darwin- Katherine power system, the Commission approved targets to apply for the network regulatory period of 1 July 2014 to 30 June 2019.

The targets for circuit based measures ACOD and FCO were achieved while the targets for transformer measures ATOD and FTO were not achieved. The transformer measures are based on a small number of events (target 0.8 events and actual two events) so this is considered to be a small perturbation on what has been sustained year-on-year improvement since 2012-13.

PWC measured the performance of the transmission network against the targets.

The transmission circuits in Darwin-Katherine meet both ACOD and FCO targets. Causes for failures are summarised in the NMP. PWC reported the most significant cause of sustained outage events on the transmission network were outages that occurred during adverse weather conditions.

There were two unplanned transformer outages in the Darwin-Katherine system in 2015–16 resulting in the FTO target not being met. The actual duration of these failures also resulted in the ATOD target not being met. However, no information is provided in NMP for the causes of these unplanned outages. Table 7-19 shows the Darwin-Katherine area results.

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Table 7-19: Darwin-Katherine transmission network performance

Transmission performance indicators

2014-15 Target

standard

2012-13 Darwin-

Katherine adjusted results

2013-14 Darwin-


2014-15 Darwin-


2015-16 Darwin-


Target standard

met

ACOD (mins) 359 227 132 115 135 Yes

FCO 49 89 60 40 26 Yes

ATOD (mins) 123 107 55 0.0 183 No

FTO 0.8 6.0 1.0 0.0 2.0 No

Source: PWC Standards of Service reports 2013-14, 2014-15 and 2015-16.

The Commission is generally satisfied with the investigation work completed by PWC to determine the causes of circuit outages.

7.2.9 Network Constraints

There were no network constraints identified in the updated NMP. Known network constraints are being actively managed by System Control and system participants.

7.3 Incident Report Review - Networks

7.3.1 Reporting Requirements

Clause 7 of the SCTC provides information on reporting requirements in relation to reportable incidents.

an initial report is to be provided to the Utilities Commission within 14 business days of any reportable incident. Insufficient evidence has been provided to AEMO to determine whether this requirement was adhered to for all incidents; and

a final report on any major reportable incident is to be provided to the Utilities Commission as soon as reasonably practical. Actual reporting timeframes varied from 71 business days to 134 business days. The average reporting time was 96 business days. By way of comparison, the average reporting time in the NEM was 65 business days.

7.3.2 Major Reportable Incidents – Transmission Network

There were 29 major reportable incidents during 2015-16, of which eight related to the transmission network as shown below in Table 7-20. Detailed reports for all eight transmission network-related incidents were prepared by PWC and AECOM, a consultant engaged by PWC.

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Table 7-20 Incident summary

Incident System* Description CauseIncident date

Reporting date

Time to report (business days)

Prepared by

Feeder 6 trip TC UFLS Stage 1 Not supplied 23/09/2015 18/02/2016 103 PWC

McMinns ZSS

tripped

DK Loss of McMinns ZZS Protection failure 14/11/2015 30/05/2016 113 AECOM

Manton-Bachelor-

Pine Creek line trip

DK 132kV Line Separation; Pine Creek and

Katherine Islanded; UFLS Stage 1 in

Katherine

Lightning 08/12/2015 22/06/2016 134 AECOM

Brewer-Sadadeen

slow clearance

AS UFLS Stage 3A Protection failure 09/01/2016 29/04/2016 76 PWC

Pine Creek –

Katherine line trip

DK 132kV PK-KA Line Tripped- UFLS Stage 2

in Katherine Island

Lightning 24/01/2016 22/06/2016 103 AECOM

Manton-Pine Creek

line trip

DK 132kV PK-MT Line Separation – Pine

Creek and Katherine Islanded -Pine Creek

and Katherine Black

Lightning 12/03/2016 24/06/2016 71 PWC

Pine Creek –

Katherine line trip

DK 132kV PK-KA Line Separation – Katherine

Islanded – Katherine Black

Lightning 13/03/2016 19/07/2016 88 PWC

Pine Creek –

Katherine line trip

DK 132kV PK-KA Line Separation – Katherine

Black

Unknown 09/04/2016 29/07/2016 78 PWC

* Darwin-Katherine (DK), Alice Springs (AS) and Tennant Creek (TC).

Source: PWC

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For the fault at McMinns ZZS the protection systems failed to operate as designed and resulted in loss of load to the substation for a feeder fault.

The Commission notes the total number of major events is relatively low and it is commendable that just one event is attributable to an equipment failure, which may have been avoidable by routine maintenance.

7.3.3 Recommendations arising from investigations

In accordance with the SCTC System Control provides the Commission with reports on incidents. AEMO has reviewed the major incidents reported using the following criteria:

timeliness of the reporting process and whether the investigation process was appropriate;

whether the recommendations arising from the investigation appear to be tracked and followed up in a systematic manner;

any trends noted from the frequent islanding of the Katherine power system; and

any other trends noted.

7.3.4 Recommendations arising from investigations

As discussed above AMEO has undertaken reviews of the incident reports provided by System Control. Arising from AEMO’s review AEMO has made a number of recommendations relating to individual incidents. Note that the incident reports discussed in this section relate to transmission incidents.

Table 7-21 Recommendations to major transmission incidents

Incident Recommendation

Feeder 6 trip (Tennant Creek)

Review of UFLS scheme to include rate of change of frequency settings Review performance of governor controls for Tennant Creek generation

units Review spinning reserve policy for Tennant Creek power system Development of dynamic simulation model of Tennant Creek power system Automatic grid control system to provide frequency support

McMinns ZSS tripped Review/implement the following schemes across the Darwin-Katherine network: Supervision of HV circuit breaker trip circuits Circuit breaker fail schemes to use undercurrent and circuit breaker status

checks Latching or time delays of protection trip signals to allow circuit breaker

operation Auto-reclose schemes for overhead lines.

Manton-Bachelor-Pine Creek line trip

Review UFLS settings at Katherine ZSS and consider implementing rate of change of frequency settings

Review programmable logic control scheme/logic at Katherine and Katherine power station

Pine Creek-Katherine line trip

Brewer-Sadadeen slow clearance

Replace SPAJ 140C relay – completed Disable supervision function in P442 – completed Enable over current and earth fault settings on P442 – completed

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Incident Recommendation Check voltage transformer (VT) neutral grounding Update drawings in relation to VT Review of VN setting in all P442 relays Review coordination of spinning reserve, under and over frequency

protection Review factors triggering frequency oscillations

Pine Creek – Manton line trip (system black)

Reallocation of capacitors in UFLS scheme – completed Review operational procedures related to lightning activity around the

Manton-Batchelor-Pine Creek-Katherine line Install TESLA at Pine Creek Restore connection to TESLA at Katherine power station Conduct performance testing, code compliance testing and model validation

of the Katherine Pine Creek power system. Review reactive power capability of Pine Creek generation units

Pine Creek – Katherine line trip (system black)

Repairs to PK03 circuit breaker – completed Review Katherine 132/22kV No1 transformer protection settings –

completed Review operational procedures related to lightning activity around the Pine

Creek-Katherine line Ensure sufficient generation available in Katherine island when at risk of

separation

Pine Creek – Katherine line trip (system black)

Review Katherine 132/22kV No1 & No2 transformer protection settings Investigate Katherine power station ‘black start’ sequence disable fail Conduct performance testing, code compliance testing and model validation

of the Katherine-Pine Creek power system

Source: PWC

The Commission makes no further observations on progress of implementing the recommendations already made in the original reports. Common themes in recommendations cover: under frequency load shedding schemes;

spinning reserve policy;

protection/control systems; and

performance testing and modelling.

7.3.5 Katherine and Pine Creek Region

The Commission observes that Katherine and Pine Creek are over represented in the total number of major events. Katherine is connected to the Darwin system by a single 132kV transmission line via the Pine Creek and Manton substations, a distance of around 300 kilometres. A fault anywhere along this line will result in the islanding of Katherine.

Of the major reportable network events in Darwin-Katherine, five of six impacted Katherine, three of which resulted in a loss of supply to customers in Katherine.

Four of these incidents were reported as caused by lightning, with the cause of the remaining incident unknown. The power system was not in a secure operating state prior to these system black like events.

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Clause 3.2.10 of the Code requires the power system to be operated as it is and will remain in a secure operating state to the extent practicable. This is managed by System Control and system participants in consideration of the inherent radial design and limitations of the power system in the Katherine and Pine Creek region.

For three of these incidents the reports state the power system was operated in compliance with the SCTC but provide no evidence to support this. Reports on the other two incidents do not address compliance with the SCTC. Notwithstanding, the Commission has seen a general improvement in the quality of incident reporting since and will further investigate these incidents and issues in the 2016-17 review.

Two possible strategies exist for reducing the number of events; reduce the susceptibility of the line to lightning strikes (PWC responsibility) or increase the ability of the Pine Creek-Katherine area to maintain its own frequency (T-Gen and System Control responsibility). Both strategies should be investigated, with considerations being given to cost impacts and expected levels of reliability.

This issue is also further discussed in section

Source: T-Gen Standards of Service Report 2015-16 from a generation perspective.

The tower earthing and ground wire arrangement on the Darwin to Katherine line will be investigated to determine if improvements can be made, as part of the 2016-17 power system review.

7.4 Assessment of PWC Networks’ Planning Mechanisms under the NMP

PWC Networks produces an NMP 2013-14 to 2018-19 with a five-year planning horizon as part of its assessment of the transmission and distribution network to meet existing and future demand. The last NMP was produced in 2013-1435 and a yearly update has been provided since in January 2016 and January 2017. This provides updates for the following: updated charts that replace the charts in the NMP and provide data based on the 2015-16 year;

transmission line capacity/utilisation information to replace Appendix 2 of the NMP;

substation capacity/utilisation information to replace Appendix 3 of the NMP;

regional load profile information to replace Appendix 4 of the NMP;

ZZS data sheets, this is a new appendix to the NMP;

system fault level data, this is a new appendix to the NMP; and

customer standards of service report to replace chapter 6 of the NMP.

The Commission considers the NMP demonstrates, at a high level, that PWC has suitable systems in place to monitor the performance of the network and plan work required to maintain the adequacy of the network.

The Commission expects that PWC will continually update its planning document to reflect changes in the industry, which might include adopting or integrating its planning into the DAPR or other appropriate NER planning arrangements.

35 Power and Water Corporation Network Management Plan, 2013-14 to 2018-19 - https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf

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https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf

https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf


The Commission reviewed the information presented in both NMP reports and, where necessary, obtained additional information from PWC for its review.

The Commission considers the following criteria as critical to PWC’s assessment of network adequacy (Chapter 7 and 8): Planning and monitoring. PWC should have the capacity to measure, plan, operate, maintain and

augment the network in order to maintain the adequacy of the system.

Existing and future system utilisation should be low enough to allow for load growth, peak loads and loadings during equipment outages. Conversely utilisation should be high enough to avoid unnecessary augmentation and costs to customers. This assessment is made at the following system levels:

- zone;

- transmission line;

- substation;

- feeders;

- distribution substation; and

- low voltage (LV) network.

Poorly performing feeders. PWC should have plans to bring the reliability of any poorly performing feeders up to a satisfactory level.

Fault levels. Electrical equipment is designed to withstand current and associated short-circuit forces in the event of a fault. PWC should have documents that record what current system fault levels are and the design capacity of each installation. They should also have processes to ensure new and existing equipment capability is not exceeded by the system fault levels.

Condition of the asset. PWC should carry out preventative maintenance, planned corrective maintenance and asset replacements to reduce the probability of unexpected plant failure, at an acceptable cost.

Demand management. PWC should document the alternative strategies considered to meet the system demand. These activities can be different from the traditional methods, which were focused exclusively on upgrade of generation and network capacity to meet a higher system demand. The modern approach adopted by PWC includes considering new tariff structures, power factor correction, load shifting and embedded generation. Collectively these strategies are known as ‘non-network solutions’.

Security of the system. The PWC power system should continue to operate under reasonable network contingency conditions. There are some network configurations like radial transmission systems or single transformer ZSS where loss of supply is unavoidable. In these cases, there should be plans in place to restore supply to customers quickly.

Reliability of supply. PWC is required to publish reliability data in their annual ‘standards of service’ report in accordance with the Commission’s ESS Code. This data should show improving reliability over time.

7.4.1 Improvements to PWC’s Network Management Plan

In the NEM, distribution and transmission network providers develop and publish an Annual Planning Report outlining its strategies and plans for the next five-year period in relation to its assets. The Commission suggests the following NMP improvements: transmission line utilisation:

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- AEMO proposes the existing 132 kV circuits have spare capacity to accommodate additional load;

fault levels:

- both fault levels and circuit breaker interruption capability should be included within the NMP. Currently, only fault levels are included; and

- both balanced and unbalanced fault levels for committed changes to the transmission network should be included within the NMP;

voltage control management:

- historical performance of voltage and reactive power control, and voltage and reactive power management plan to meet future maximum and minimum demand should be included within the NMP; and

- PWC to investigate other cost-effective solutions (for example, reactive plants) instead of running Pine Creek generators to manage over voltages during light load conditions;

Power system stability:

- power system stability limits (relevant stability limits applicable to the power system) for different operating conditions should be included within the NMP;

power system stability with solar PV penetration:

- PWC to closely monitor technical issues to the power system upon increase in solar PV penetration and reduced synchronous generators in service; and

transmission network performance:

- causes for transformer outages (including proposed and planned improvements to keep future transformer outages within the targets) should be included within the NMP.

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8. Network Performance

8.1 Introduction

In this section the Commission considers:

an assessment of PWC planned and recent network enhancements;

utilisation of terminal station, ZZSs and feeders;

feeder network performance, including analysis of performance indicators under the ESS Code; and

progress against findings of previous power system reviews.

8.2 Network Utilisation

8.2.1 Terminal Station and ZSS Utilisation

In the Territory, substation average utilisation during 2015-16 was 43 per cent and it is projected to remain stable until 2019-20. Under first contingency operation the average utilisation was 81 per cent, which is significantly higher than reported in the previous year.

There are a few stations where the first contingency loading exceeds 100 per cent but the overload is modest and, provided PWC promptly executes contingency plans to return loading to an acceptable level, this can be tolerated.

There are many substations where adequate contingency supply can only be achieved by the transfer of load onto nearby substations. This method of achieving contingency supply is within industry best practice. However, this method is less transparent to industry observers and without detailed information on the actual transfers to be completed, it is not possible for the Commission to confirm the assertions in the NMP that adequate transfer capacity is available.

The Commission supports PWC in its initiative to complete an engineering investigation into the impact of cyclic loading factor on transformers, in excess of their nameplate rating for limited periods of time. PWC has not reported any progress against this initiative for the 2015-16 reporting period. Considering the Territory’s difficult climatic conditions, it would be prudent to confirm that a cyclic loading factor can be implemented without affecting the transformer service age.

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Table 8-22 provides the contingency utilisation for each substation, before any load is transferred.

Table 8-22: Summary of the substation constraints (N-1 conditions)Substation 2016-17 2017-18 2019-20Archer 113% 126% 139%Batchelor No local backup No local backup No local backupBerrimah 80% 80% 81%Brocks CreekCasuarina 75% 75% 75%Centre Yard 80% 80% 80%City ZoneCosmo Howley 64% 64% 64%Darwin Zone 87% 82% 77%Frances Bay No local backup No local backup No local backupHudson Creek 132/66kV 92% 94% 95%Humpty Doo 70% 70% 70%Katherine 90% 87% 83%Leanyer 72% 73% 74%Manton No local backup No local backup No local backupMarrakkai 36% 40% 40%Mary River No local backup No local backup No local backupMcMinnsPalmerston 114% 59% 59%Pine Creek Terminal No local backup No local backup No local backupPine Creek 66/11 ZS 82% 82% 82%Pine Creek 11/22 ZS No local backup No local backup No local backupSnell StreetStrangways 125% 136% 119%Tindal 61% 59% 58%Weddell 73% 45% 48%Wishart No local backup No local backup No local backupWoolner 70% 72% 75%Lovegrove 22/11 99% 93% 86%Lovegrove 66/22 100% 100% 100%Owen Springs 100% 50% 50%Sadadeen 116% 116% 116%Tennant Creek 92% 93% 94%

Source: PWC

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8.2.2 Feeder Utilisation

The Commission acknowledges the use of 50 to 55 per cent utilisation target for 11 and 22kV feeders, as utilised by Ergon Energy, is acceptable. PWC has forecast that the average 11kV feeder utilisation will increase from 44 per cent in 2016 to 48 per cent in 2021.

PWC has provided consolidated 22 kV feeder utilisation data, shown in Figure 8-36. The only significant observation is a large number of feeders moving from 30-40 per cent loaded up to the 40-50 per cent band representing an improvement of the utilisation of the assets. It is assumed remedial action will be taken to rectify the three feeders that are expected to become overloaded.

Figure 8-36: 22kV PWC feeder utilisation

Source: PWC

PWC has also provided consolidated 11 kV feeder utilisation data, shown in Figure 8-37. This information shows the 11 kV feeders are more heavily loaded than the 22 kV feeders with 26 per cent of feeders loaded at more than 70 per cent by 2021. This is considered manageable provided action is taken to reduce the loading of the 17 feeders predicted to be loaded above 90 per cent. More detailed information provided shows only two 11 kV circuits are overloaded prior to 2019.

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Figure 8-37: 22kV PWC feeder utilisation

Source: PWC

8.2.3 Feeder Performance

PWC and the Commission pay particular attention to the feeders categorised as ‘poorly performing feeders’. PWC’s Feeder Upgrade Program is an annual program that uses five calendar years of interruption data to analyse outage causes for poorly performing feeders and implement corrective action. The Commission supports this program and reviews SAIDI and SAIFI results annually to validate the effectiveness of PWC upgrade actions.

The 2011-12 Review reported 18 feeders that performed as worst performing feeders. Nine of these feeders breached the threshold for two years consecutively and, as per the previous Service Code, were each termed as ‘consecutively worst performing feeder’. The 2012-13 Review reported four feeders exceeded the new threshold limit.

The NMP reports that in the 2013-14 year there were no poorly performing feeders as no feeder had breached the threshold for two years consecutively. The 2014-15 standards of service report and the 2015-16 standards of service report show that again there were no poorly performing feeders in the 2014-15 or 2015-16 periods.

The Commission notes that this represents a significant improvement in the performance of the worst feeders sustained over at least four consecutive years and is a very good result.

8.3 Planned and Recent Network Enhancements

PWC is completing or has planned large network projects that reflect the need to address capacity constraints noted above to meet the Territory’s growth in demand, replace ageing network system

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assets and improve network reliability and quality of supply. Significant projects recently completed or underway include:

Darwin city ZSS replacement (complete pre 2015-16);

Leanyer ZSS (complete pre 2015-16);

Wishart modular substation (complete pre 2015-16);

Frances Bay second transformer (complete pre 2015-16);

Strangways ZSS to replace McMinns (completed 2015-16);

22kV switchboard replacement at Tennant Creek (completed 2015-16);

Mitchell St switching station (complete pre 2015-16);

improve cyclone performance of Elizabeth River 132kV crossings to category 4 (in construction for commissioning September 2017);

Palmerston to Archer transmission line (business case approved and contract awarded);

22kV switchboard replacement at Sadadeen, Alice Springs (deferred);

new 11kV switchboard at Sadadeen, Alice Springs (preliminary business case approved, preparing design construct tender – award second half of 2017);

Berrimah ZSS replacement (deferred);

replace Casuarina ZSS 66kV switchgear (under construction completion expected October 2017);

132/66kV terminal station and transmission lines Weddell-Woolner (long-term planning);

Alice Springs replacement of corroded poles (currently undergoing assessment);

Mot Street switching station replacement (completed 1015-16);

Austin Knuckey switching station replacement (in construction);

West Bennet switching station (in planning);

Palmerston ZSS third transformer (under construction, expected completion mid 2018); and

implement an Outage Management System (planning).

A summary of the major and minor capital project expenditures as proposed by PWC is shown in Table 8-23.

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Table 8-23: Forecast capital expenditure ($ million, real $2013-14 with input cost escalation) Project ($M) 2016-17

(forecast)2017-18(budget)

2018-19(projection)

2019-20(projection)

Replace Berrimah ZSS 2.0 9.4 1.3Archer ZSS – Palmerston ZSS 66kV line

4.0 9.8

Replace port feeder 1.1Alice Springs – Corroded poles and high risk poles

1.4 3.1 3.5

Other capital projects 57.6 40.6 34.0 38.1Total 63.0 55.5 46.9 40.6

Source: PWC

The Commission supports PWC’s large capital project program but notes the following:

The 2013-14 NMP does not provide adequate details of the different options considered during the planning phase of each project. Future NMPs should provide appropriate detail for the Commission to confirm that PWC has reviewed its investment options.

Power system reporting should provide comprehensive and authoritative data to assist identification of investment options for the Commission to review. The Commission aims to provide an independent evaluation on how PWC is deploying investments to address emerging network constraints in the annual Power System Review.

The Commission recommends PWC provide more exhaustive detail regarding the options considered, including engineering review, financial and time considerations.

8.4 Reliability of Network Performance

Reliability performance of PWC’s feeder network performance is analysed in this section.

PWC has increased expenditure on maintenance and capital projects in recent years. If this expenditure is appropriately targeted on those parts of the network, significantly contributing to system reliability issues, this should result in a progressive improvement in the reliability of the network. Moreover, improvement is evident in the poorly performing feeder category.

Under the ESS Code, licensed network entities are required to report performance against specific indicators and targets for network distribution and transmission.

8.4.1 Feeder Network Performance

To measure the reliability performance of PWC feeders, the key indicators are:

SAIDI, which indicates the average duration of network and generation-related outages experienced by a customer; and

SAIFI, which indicates the average number of network and generation-related outages experienced by a customer.

PWC advised that the following activities were undertaken commencing 2014 to improve the SAIDI and SAIFI performance of the networks. These activities are ongoing:

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replacement of dated air break switches with remotely controllable gas break switches;

hardware upgrades such as replacing pin insulators with post insulators and installing fiberglass cross arms;

installation of animal guards;

underground cable monitoring and replacement

installation of fault indicators to aid rapid fault location; and

trials of new technologies such as fuse savers.

To assess relative performance of PWC with regulatory expectations elsewhere in Australia, the Commission has compared PWC Networks’ 2015-16 performance with the minimum service standards applicable to Ergon. The analysis Table 8-24 below shows PWC feeder performance is improving.

The Commission does note that the Territory’s classification of feeders and methodology for exclusions differ from that applied by Ergon.

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Table 8-24: PWC and Ergon SAIDI and SAIFI comparison

Key Indicator 2011-12 2012-13 2013-14* 2014-15 2015-16 (PWC)

2015-16 (Ergon)** PWC Target Ergon Energy

Target Meet (Y/N)

SAIDI

SAIDI CBD 10.4 1.1 0.1 0.7 1.6 n/a 18.8 n/a Y / n/a

SAIDI Urban 67 111 52 127.6 113.0 127.7 136.0 149 Y / Y

SAIDI Short Rural 256 536 229 372.9 339.8 349.6 496.3 424 Y / Y

SAIDI Long Rural 1 108 156 755.9 610.3 954.7 2164.9 964 Y / Y

SAIFI

SAIFI CBD 0.4 0.03 0.6 0.1 0.0 n/a 0.4 n/a Y / n/a

SAIFI Urban 2.5 2.5 1.6 1.6 2.0 1.272 2.5 1.98

SAIFI Short Rural 10.4 9.1 4.1 4.8 4.4 3.023 8.1 3.95 Y / N

SAIFI Long Rural 12.2 3.4 7.2 9.4 6.766 35.1 7.40 Y / NSource: PWC Standards of Service Reports 2013-14, 2014-15, 2015-16 and Ergon Minimum Service Standard36.

* For the purposes of this report the Commission has chosen to remove the 2013-14 system black incident from the SAIDI data but not from the SAIFI data. This is justified on the basis that the cause of the System Black was within PWC’s control but the duration was exacerbated by generation related issues.

** As stated above, comparisons with Ergon should be treated with caution.

36 Ergon Energy 2016 Distribution Annual Planning Report (DAPR) < https://www.ergon.com.au/__data/assets/pdf_file/0006/167559/DAPR-2016.pdf>

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https://www.ergon.com.au/__data/assets/pdf_file/0006/167559/DAPR-2016.pdf


8.4.2 SAIDI and SAIFI Historical Comparison

To assess feeder performance, the Commission has compared the 2015-16 adjusted SAIDI and SAIFI performance to the performance of the latest five-year period. There does not appear to be any discernible trend for either SAIDI or SAIFI, with performance fluctuating significantly, in particular for SAIDI.

The Commission notes that PWC has met its SAIDI targets since 2013-14 in all feeders, and all its SAIFI targets since 2013-14 except for CBD feeder in 2013-14, and will review the targets and whether the targets are set at appropriate levels in its review of the ESS Code in mid-2017.

8.5 Progress against Findings from 2013-14 Power System Review

In the 2013-14 Review, the Commission provided a list of recommendations for PWC to address. It is the intention of the Commission to monitor the progress of recommendations from all reviews, to document and investigate the reason for any lack of progress or delays and provide a view as to whether these delays are justified. Progress against the 2014-15 Review recommendations is detailed below.

The main reliability concern was related to the transmission lines from Channel Island to Hudson Creek. Significant work has been completed to address this concern including circuit breaker replacements, protection replacements (completed 2015-16), lightning protection modifications and earth grid testing. Recommended improvements to tower footing earthing for lightning protection are yet to be addressed.

Improvements in aligning it with the requirements of the NER have been made in comparison in the 2013-14 report. However, the Commission has seen no evidence of progress relating to:

changes from the previous year’s reporting;

options analysis to fully document the major strategies and plans in the yearly report; and

details of the expected commissioning month of each specific major project.

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9. Customer Service

9.1 Introduction

This is the third financial year for which the ESS Code has operated for the full period. For the 2015-16 year, PWC and Jacana reported relevant network services and retail services performance.

In March 2017, the Commission commenced a review of the ESS Code and its performance indicators, with the review expected to be completed by mid-2017.

The key measures and structure of this year’s review of customer service performance reflect the ESS Code released 1 December 2012.

The relevant schedules of the ESS Code relating to customer service performance are:

schedule 2 – Network Services Performance Indicators; and

schedule 3 – Retail Services Performance Indicators.

Specifically, the PWC data provides: network indicators, which includes ‘quality’ (in turn, includes quality of supply and complaints);

and

customer service indicators.

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9.2 PWC Network Services Performance

9.2.1 Reconnections and New Connections

Performance of reconnections and new connections for 2015-16

The ESS Code outlines the following indicators for measuring of performance relating to connections and reconnections37:

the percentage and total number of reconnections not undertaken within 24 hours of receipt by the network provider of a valid request for reconnection from the customer;

the percentage and total number of new connections in the CBD area or urban areas not undertaken within five business days, excluding connections to new subdivisions where minor extensions or augmentation is required (this measure is included in the PWC Standards of Service Report 2014-15);

the percentage and total number of new connections in rural areas not undertaken within 10 business days, excluding connections to new subdivisions where minor extensions or augmentation is required (this measure is included in the PWC Standards of Service Report2014-15); and

the number and average length of time taken to provide new connections in urban areas to new subdivisions where minor extensions or augmentation is required (this measure is included in the PWC Standards of Service Report 2014-15).

PWC’s performance relating to reconnections and new connections for 2015-16 is provided in the tables 10.1 and 10.2.

Table 9-25 Connections and reconnections performance – PWC

Performance Measure Total numberPercentage of total not

undertaken within timeframe

2014-15 2015-16 2014-15 2015-16

Re-connections not undertaken within 24 hours38 15 418 16 972 0.032% 0.047%

New connections not undertaken in the CBD/urban areas within five days (excluding where minor extensions or augmentation is required)

36 15 2.07% 1.3%

New connections not undertaken in the rural areas within 10 days (excluding where minor extensions or augmentation is required)

0 0 NA NA

Source: PWC

37 Schedule 2, 1.8.2 (a), ESS Code, Northern Territory of Australia, 2013.38 This measure was not reported in PWC’s 2014-15 or 2015-16 Standards of Service report but reported

separately to the Commission in May 2016.

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Table 9-26 New Connections in urban areas to new subdivisions – PWC

Performance Measure

Total Avg. Time (weeks)

2014-15 2015-16 2014-15 2015-16

New Connections in urban areas to new subdivisions

104 83 11.1 11

Source: PWC Standards of Service Report 2014-15 and 2015-16

9.2.2 Quality of Supply Issues

Quality of supply performance for 2015-16

The reporting requirements for complaints relating to network quality of supply are ‘the percentage and total number of complaints associated with the transmission network and distribution network quality of supply issues’.

The percentage of complaints relating to PWC’s quality of supply performance, by region, is summarised in Figure 9-38 and Figure 9-39.

Figure 9-38: Percentage of customer complaints relating to quality of supply and reliability

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Figure 9-39: Customer complaints relating to quality by region

Source: PWC Standards of Service report 2015-16.

The Commission remains concerned that the information reported does not provide enough insight into the nature or cause of the complaints for the Commission to form a view as to whether the response, from a planning or operational sense, is adequate.

The Commission recommends the measurement and routine analysis of power quality data through the network as a method of determining the actual network performance. This data can then be used to understand the customer notification data in context.

9.2.3 Network Related Activities Complaints

The reporting requirements for complaints regarding network-related activities are ‘the percentage and total number of complaints associated with transmission network and distribution network-related activities segmented into complaint categories’.

PWC provided the data set out in Table 9-27 and Table 9-28 relating to network-related activity complaints. The category breakdown has changed each year and the Commission recommends PWC settle on a standardised format so meaningful year-on-year comparisons can be made.

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Table 9-27 2015-16 customer complaints due to network-related activities – PWC

Network Related Activities

Darwin

Katherine Tennant Creek

Alice Springs

Metering 69 7 3 15

Reliability 50 1

Planned Outage 26 1

Customer Claims (loss/damage) 16 1 1 1

Faulty Streetlight 18 1 2

Connection/Disconnection 12 1 3 1

Solar Photovoltaic Panels 4 2 4

Other 47 3 2

Total 242 15 8 26Source: PWC

Table 9-28 Customer complaints due to network-related activities over time – PWC

Total

2013-14 2014-15 2015-16

Darwin 123 109 242

Katherine 2 8 15

Tennant Creek 7 0 8

Alice Springs 2 15 26

Total 134 132 291

Source: PWC Standards of Service Report 2015-16.

The number of complaints has increased significantly for 2015-16. However, the categories do not provide meaningful comparisons nor any insight into the causes of the increases, and the Commission will continue to work with PWC to break down the categories of reporting more meaningfully.

9.2.4 Written Enquiry Response – Networks

PWC reported just one written complaint in each of the Darwin-Katherine and Alice Springs networks. One day was taken to respond to each.

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The Commission will investigate in future reviews (and during its 2017 review of the ESS Code) on how complaints are defined in greater detail, and whether these are defined appropriately in accordance with electricity industry practice.

9.2.5 Telephone Call Response

In schedule 2, 1.8.3 (b) the ESS Code specifies that ‘where relevant, and unless the Commission otherwise considers appropriate, the results [of telephone call response] will be a combined total for both PAWC Networks and PAWC Retail’.

While no telephone call response data has been included in reporting of network services performance, data has been provided in reporting of retail services performance. It is therefore assumed that the reporting of telephone call response relates to network and retail services combined.

PWC is required to provide these indicators by the ESS Code and the Commission will continue to work with PWC to better understand its reporting obligations under the ESS Code post-structural separation and as the Commission reviews the ESS Code indicators in 2017.

9.3 Jacana Energy Retail Services Performance

9.3.1 Telephone Call Response

Jacana established its own call centre in January 2016 as one of the final steps to complete structural separation from PWC. Prior to this the call centre was operated by PWC.

The performance indicators for phone answering include:

average time taken to answer the phone;

percentage and total number of calls not answered within 30 seconds; and

the percentage and total number of calls abandoned.

Table 9-29 Telephone call answering reporting – Jacana Energy and PWC (2015-16)

2015-16 2014-15 2013-1439

Average time taken to answer the phone 100 seconds 45 seconds 371 seconds

Number of calls NR 122 555 245 132

Total % Total % Total %

Calls not answered within 30 seconds of the caller asking to talk to a person

NR 41 35 541 29 182 868 74.6

Calls abandoned 7836 NR 3309 2.7

46 575 19

*NR – Not reported

Source: PWC and Jacana

39 Telephone call answering reporting measures were reported by PWC prior to structural separation on 1 July 2014.

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As the ‘hard’ structural separation of Jacana Energy continues to be implemented at an operational level, this also affects the way reporting categories and performance data is tracked. The Commission understands Jacana has amended the reporting categories and the numbers it tracks from those previously reported by PWC to be more consistent with definitions and categories reported in the NEM, which is encouraging. However this leads to difficulties in comparing the complaint data quantitatively and trends should be evident once two to three years of data is accumulated and reported by Jacana.

The Commission accepts Jacana’s explanation that telephone answering performance deteriorated principally during the last three months of the transition from PWC operation of the call centre to Jacana operation. This assertion is supported by the proportion of calls answered in less than 30 seconds during these three months of 52 per cent, 25 per cent and 13 per cent, respectively. On this basis the Commission expects telephone answering performance will return to trend in the 2016-17 reporting period.

Also ‘for the purpose of calculating retail services performance indicators for Phone Answering, Complaints and Written Enquiries – only include those customers that are taking (or likely to take less than) 160 megawatt hours of electricity from the distribution network during the reporting period’. It is not explicitly stated, but assumed, that the Jacana’s data only includes this subset of customers.

Additionally, ‘Where relevant, and unless the Commission otherwise considers appropriate, the results [of telephone call response] will be a combined total for both PWC Networks and PWC Retail’.

9.3.2 Retail-Related Complaints

Number of customer complaints for 2015-16

Number of customer complaints for 2015-16

The performance indicator for complaints ‘is the percentage and total number of complaints associated with retail services segmented into complaint categories. For the purpose of calculating retail services performance indicators for Phone Answering, Complaints and Written Enquiries – only include those customers that are taking (or likely to take less than) 160 megawatt hours of electricity from the distribution network during the reporting period.’

Complaints data provided from 2014-15 is specific to electricity whereas in the past this data has related to electricity, water and network issues combined.

The Commission accepts Jacana’s explanation that complaints appear to have increased largely due to a change in the ‘definition of complaint and developed categories (to be) consistent with those applied by the AER for retail monitoring in the national electricity market’. The Commission assumes this means the definition of ‘complaint’ has been broadened leading to an apparent increase in the number of complaints.

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Table 9-30: Breakdown on complaint numbers

Category Darwin Alice Springs Katherine Tenant Creek

Billing 216 31 8 1

Marketing 0 0 0 0

Other 42 5 1 2

Total 258 36 17 3

9.3.3 Customer Hardship Programs

The level of hardship program penetration is summarised in Table 10.8. Jacana is making improvements to their hardship program and these efforts are showing initial signs of success. The following text is quoted directly from the Jacana standards of service report:

‘Jacana Energy is committed to reducing disconnection rates and we have recently implemented a new SMS messaging service that warns customers of the need to pay their outstanding account immediately prior to being disconnected for non-payment. We are already seeing significant reductions in the rate of disconnections as a result.

Another notable development highlighted in our results is the number of customers on hardship programs has reduced in this reporting period, from 534 customers in 2014-15 to 364 customers in 2015-16.

We are undertaking an internal review of our customer hardship assessment program to ensure we are correctly identifying customers in need of assistance early enough and provide them with the right tools.

One measure that may be contributing to the fall in hardship numbers is the significant increase in the number of customers who successfully completed their hardship programs. Successful completion of programs increased from 74 in the last reporting period to 211 in the current reporting period.

Jacana Energy's hardship program guidelines are set out in our Stay Connected Policy (available on the website). This policy provides customers with a range of payment options and practical advice to reduce their energy and manage their bills (including what government concessions are available to them). Our Stay Connected program is run in collaboration with welfare agencies, such as Sommerville, Anglicare, Salvation Army and Catholic Care. Customers can be identified as a Stay Connected Customer either by advising Jacana Energy through self-assessment, an internal Jacana Energy assessment process, or by referral from an independent accredited financial counsellor.

We also provide customers with timely information regarding payment assistance, including details of new initiatives and schemes, and invite customers to contact Jacana Energy to discuss alternative payment arrangements on notices or requests for payment.’

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Table 9-31 Customer hardship program summary

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Service measures associated with a customer hardship program Darwin Alice Springs Katherine Tennant Creek1) Number of customers on a customer hardship program at the end of the reporting period, with an average

electricity bill:

Total 290 54 14 6

l. between $0 and $500 31 10 2 0

ll over $500 but less than $1 ,500 140 32 4 1

lll. $'1,500 but less than $2,500 63 10 4 1

IV. $2,500 or more 56 2 4 4

2) Number of customers that completed a customer hardship program. A customer has completed a customer hardship program if the customer no longer meets the eligibility criteria (as defined in the relevant customer hardship program) due to the customer's participation in that customer hardship program 211 55 13 1

3) Number of customers that exited a customer hardship program. A customer has exited the relevant customer hardship program if the customer has come to an agreement with the relevant electricity entity to exit that customer hardship program. 1 0 0 0

4) Number of customers that were removed from a customer hardship program. A customer has been removed from the relevant customer hardship program if (in the relevant electricity entity's reasonable opinion) the customer has not complied with its obligations under that customer hardship program. 163 34 10 2

5) Number of customers on a customer hardship program that received hardship vouchers or equivalent under (and as defined in) the relevant customer hardship program 1 0 0 0

6) Number of customers on a customer hardship program that ceased to be a customer under a contract for supply with a relevant electricity entity 65 10 2 0

7) Number of customers that applied for a customer hardship program and had their application refused by a relevant electricity entity. An application is refused when a customer does not (in the electricity entity's reasonable opinion) meet the eligibility criteria in the relevant customer hardship program 0 0 0 0

8) Average electricity bill of all customers who were on the customer hardship program, as identified in 1) above $1,763.81 $1,089.42 $1,825.63 $5,433.27

9) Number of customers who have been checked for compliance 1757 276 104 28

10) Number of customers that received e-vouchers and not on hardship program between reporting period 55 13 1 0

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11) Number of hardship agency contacts 1126 265 27 12

12) Number of customers that transferred program from one property to another 5 0 0 0

13) Disconnections for failure to pay and reconnections in same name 3002 573 178 82

Source: Jacana Energy

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9.4 PWC Retail Services Performance

PWC’s 2014-15 Standards of Service Report did not include performance indicators in relation to Retail Services. The Commission will monitor PWC’s compliance with the retail services indicators in the ESS Code for 2016-17.

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Appendices

117


A Generating Units

118


Darwin-Katherine

A.1.1 Channel Island

Unit GT 1* GT 2* GT 3* GT 4* GT 5* ST 6 GT 7 GT 8 GT 9 House Set

1.65MVA

Make / Model GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 Mitsubishi GE LM6000 Trent 60 Trent 60 Cummin

C1675 D5

Engine Type Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Steam

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Reciprocating

Diesel

Fuel Type Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel Waste

Heat

Gas Gas or Diesel Gas or Diesel Diesel

MW GMC

RATING

31.6 31.6 31.6 31.6 31.6 32 36 42 42

N-1 FIRM GMC 31.6 31.6 31.6 31.6 0 16 36 42 42

N-2 FIRM GMC 31.6 31.6 31.6 0 0 0 36 42 42

Date

Commissioned

1986 1986 1986 1986 1986 1987 2000 2011 2011 2014

* T-Gen has advised that generation units 1 – 5 (GE Frame 6) have been converted to gas only but can be retro-fitted to use diesel within 24 to 48 hours.

A.1.2 Weddell

Unit Set 1 Set 2 Set 3 House Set 0.9MVA

Make / Model GE LM6000 PD GE LM6000 PD GE LM6000 PD Caterpillar 3412

Engine Type Combustion Turbine Combustion Turbine Combustion Turbine

Fuel Type Gas Gas Gas

119


MW GMC RATING 43 43 43

N-1 FIRM GMC 0 43 43

N-2 FIRM GMC 0 0 43

Date Commissioned Feb-08 Nov-08 Mar-14 2008

A.1.3 Shoal Bay and Pine Creek

Shoal Bay Pine Creek A

Unit Set 1 GT 1 GT 2 ST 3

Make / Model Caterpillar 3516G Solar Mars Solar Mars Peter Brotherhood

Engine Type Reciprocating Spark Fired Combustion Turbine Combustion Turbine Steam Turbine

Fuel Type Land Fill Gas Gas Gas Waste Heat

MW GMC RATING 1.1 9.64 9.64 7.31

N-1 FIRM GMC 0 9.64 0 3.655

N-2 FIRM GMC 0 0 0 0

Date Commissioned Aug-05 Jun-96 Jun-96 Jun-96

120


A.1.4 Katherine

Unit GT 1 GT 2 GT 3 GT4

Make / Model Solar Mars Solar Mars Solar Mars Solar Titan 130

Engine Type Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine

Fuel Type Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel

MW GMC RATING 7.4 7.4 7.4 12.5

N-1 FIRM GMC 7.4 7.4 7.4 0

N-2 FIRM GMC 7.4 7.4 0 0

Date Commissioned 1987 1987 1987 Jul-12

121


A.2 Tennant Creek

Unit Set 1 Set 2 Set 3 Set 4 Set 5

Make / Model Ruston 8ATC Ruston 8ATC Ruston 8ATC Ruston 8ATC Ruston 8ATC

Engine Type Reciprocating Diesel Reciprocating Diesel Reciprocating Diesel Reciprocating Diesel Reciprocating Diesel

Fuel Type Diesel Diesel Diesel Diesel Diesel

MW GMC RATING 1.300 1.300 1.300 1.300 1.300

N-1 FIRM GMC 1.300 1.300 1.300 1.300 1.300

N-2 FIRM GMC 1.300 1.300 1.300 1.300 1.300

Date Commissioned

Unit Set 10 Set 11 Set 12 Set 13 Set 14 Set 15 Set 16 Set 17

Make / Model Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Solar Taurus

Cummins QSK60

Cummins QSK60

Engine Type Reciprocating Spark Fired

Reciprocating Spark Fired




Combustion Turbine

Reciprocating Diesel


Fuel Type Gas Gas Gas Gas Gas Gas or Diesel

Diesel Diesel

MW GMC RATING 0.958 0.958 0.958 0.958 0.958 3.900 1.500 0.000

N-1 FIRM GMC 0.958 0.958 0.958 0.958 0.958 0.000 1.500 0.000

N-2 FIRM GMC 0.958 0.958 0.958 0.958 0.958 0.000 0.000 0.000

Date Commissioned

1999 1999 1999 1999 1999 2004 February 2008

December 2010

122


A.3 Alice Springs

A.3.1 Ron Goodin

Unit Set 1 Set 2 Set 3 Set 4 Set 5 Set 6 Set 7 Set 8 Set 9

Make / Model

Mirrlees KVSS12 Mirrlees KVSS12 Mirrlees KV16P Major Mirrlees KV16P Major Mirrlees KV16P Major

Pielstick PC2-3 V16 DF



ASEA GT35C

Engine Type Reciprocating Diesel


Reciprocating Dual Fuel






Combustion Turbine

Fuel TypeDiesel Diesel Diesel and Gas Diesel and Gas Diesel and Gas

Diesel and Gas

Diesel and Gas

Diesel and Gas

Gas or Diesel

MW GMC RATING 1.900 1.900 4.200 4.200 4.200 5.500 5.500 5.500 11.700

N-1 FIRM GMC 1.900 1.900 4.200 4.200 4.200 5.500 5.500 5.500 0.000

N-2 FIRM GMC 1.900 1.900 4.200 4.200 4.200 5.500 5.500 0.000 0.000

Date Commissioned 1966 1967 1973 1973 1975 1978 1981 1984

November 1987

A.3.2 Owen Springs

Unit OSPS A (Ex RGPS H set) OSPS 1 OSPS 2 OSPS 3

Make / Model Solar Taurus 60 MAN 12V 51/60 DF MAN 12V 51/60 DF MAN 12V 51/60 DF

Engine Type Combustion Turbine Reciprocating Dual Fuel Reciprocating Dual Fuel Reciprocating Dual Fuel

Fuel Type Gas or Diesel Dual Fuel Dual Fuel Dual Fuel

MW GMC RATING 3.900 10.700 10.700 10.700

N-1 FIRM GMC 3.900 0.000 10.700 10.700

N-2 FIRM GMC 3.900 0.000 0.000 10.700

Date Commissioned 2004 October 2011 October 2011 November 2011

123


A.3.3 Brewer PPA

Unit G 1 G 2 G 3 G 4

Make / Model Waukesha Waukesha Waukesha Waukesha

Engine Type Reciprocating Spark Fired Reciprocating Spark Fired Reciprocating Spark Fired Reciprocating Spark Fired

Fuel Type Gas Gas Gas Gas

MW GMC RATING 2.128 2.128 2.128 2.128

N-1 FIRM GMC 2.128 2.128 2.128 0.000

N-2 FIRM GMC 2.128 2.128 0.000 0.000

Date Commissioned 23 December 1996 23 December 1996 23 December 1996 23 December 1996

Note: Brewer PPA’s arrangements with Territory Generation expired in March 2017.

A.3.4 Uterne PPA

Unit G 1 G 2

Make / Model SunPower T20 Tracker

Engine Type Photovoltaic Photovoltaic

Fuel Type PV PV

MW GMC RATING 0.964 3.1

N-1 FIRM GMC 0.000 0.000

N-2 FIRM GMC 0.000 0.000

Date Commissioned 24 June 2011 August 2015

124


B Summary of Electricity Consumption and Maximum Demand Projections

B.1 Energy Consumption Forecast

FYE DARWIN-KATHERINE ALICE SPRINGS TENANT CREEK

2014-15 (actual) 1623.00 221.20 29.20

2015-16 (actual) 1706.95 219.00 29.91

2016-17 1631.10 220.92 29.69

2017-18 1636.43 221.46 29.81

2018-19 1641.77 221.99 29.93

2019-20 1648.96 222.80 30.06

2020-21 1658.76 223.61 30.20

2021-22 1668.77 224.42 30.32

2022-23 1677.86 225.47 30.46

2023-24 1686.96 226.53 30.59

2024-25 1696.06 227.59 30.73

2025-26 1707.92 228.68 30.86


B.2 Maximum Demand with Probability of 50 per cent and 10 per cent Exceedance – Neutral Scenario

FYE DARWIN-KATHERINE ALICE SPRINGS TENANT CREEK

2011-12 (actual) 282 53 6.8

2012-13 (actual) 293 52 7.0

2013-14 (actual) 280 51 6.6

2014-15 (actual) 291 51 6.7

2015-16 (actual) 293 53 6.8

POE50 POE10 POE50 POE10 POE50 POE10

2016-17 292 301 55 58 7.16 7.58

2017-18 289 299 55 57 7.2 7.62

2018-19 289 299 55 58 7.20 7.61

2019-20 290 300 55 58 7.19 7.60

2020-21 291 302 55 58 7.19 7.61

2021-22 293 304 55 58 7.19 7.61

2022-23 294 305 56 59 7.18 7.60

2023-24 295 306 56 59 7.41 7.85

2024-25 297 308 56 59 7.42 7.86

2025-26 299 310 57 60 7.42 7.85


B.3 Zone Substation Maximum Demand

AEMO’s zone substation forecasts represent the neutral scenario.

Forecasts (50 per cent POE level) for the Darwin-Katherine and Alice Springs regions are summarised in the tables below. There is only one zone substation in the Tennant Creek network therefore the forecast for this substation is the same as the regional forecast in B.2 Maximum Demand with Probability of 50 per cent Exceedance – Neutral Scenario.

Darwin-Katherine Zone Substation

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Archer 31.30 35.52 40.16 45.80 46.84 47.55 48.28 49.04 49.79 50.67

Batchelor 1.83 1.81 1.82 1.82 1.83 1.84 1.85 1.86 1.87 1.88

Berrimah 29.71 30.43 32.82 33.12 33.06 32.96 32.28 31.62 30.93 30.31

Casuarina 37.34 36.96 37.07 37.17 37.41 37.62 37.86 38.10 38.34 38.67

Centre Yard 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40

Cosmo Howley 4.46 4.46 4.46 4.46 4.46 4.46 4.46 4.46 4.46 4.46

Darwin 37.05 35.87 35.18 34.47 33.90 33.28 32.68 32.07 31.46 30.91

Frances Bay 25.68 25.89 26.43 26.96 27.60 28.23 28.87 29.52 30.18 30.91

Hudson Creek Transmission Terminal Station

216.80

214.79

215.62

216.39

218.01

219.43

220.97

222.59

224.17

226.31

Humpty Doo 1.32 1.30 1.31 1.31 1.32 1.32 1.33 1.33 1.34 1.35

Katherine 26.73 26.33 26.28 28.49 28.54 30.21 30.26 30.31 30.36 30.49

Leanyer 19.50 19.28 19.31 19.34 19.44 19.53 19.62 19.73 19.82 19.97

Manton 7.41 7.32 7.34 7.35 7.39 7.42 7.46 7.49 7.53 7.59

Marrakai 0.81 0.80 0.80 0.80 0.81 0.81 0.82 0.82 0.82 0.83

Mary River 3.14 3.10 3.11 3.11 3.13 3.14 3.16 3.17 3.19 3.21

McMinns 37.05 41.13 30.55 31.34 32.26 33.15 34.06 35.00 35.93 36.97

Palmerston (22 - 11kV load)

10.15 10.15 10.27 10.39 10.56 10.71 10.87 11.04 11.20 11.40

Palmerston (66 - 11kV load)

51.06 53.32 54.28 55.22 56.39 57.51 58.67 59.86 61.04 62.39

Pine Creek (22-11kV load)

1.10 1.09 1.09 1.09 1.10 1.10 1.11 1.11 1.12 1.13


Tindal (22kV load)

5.25 5.14 5.11 7.34 7.34 8.97 8.97 8.97 8.97 8.99

Union Reef 9.64 9.66 9.69 9.71 9.73 9.75 9.78 9.80 9.82 9.85

Weddell 15.28 5.20 5.19 5.18 5.19 5.20 5.20 5.21 5.22 5.24

Wishart Modular Substation

3.99 4.63 5.81 7.00 7.77 8.61 9.71 10.82 11.72 12.54

Woolner 39.27 39.79 40.83 41.86 43.07 44.24 45.44 46.67 47.90 49.26

Alice Springs Zone Substation40

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Brewer + Sadadeen 22 kV Loads

12.49 12.63 12.93 13.23 13.54 13.80 14.12 14.51 14.84 15.18

Lovegrove (22-11kV load)

23.68 22.98 22.59 22.19 21.79 21.31 20.91 20.61 20.21 19.82

Lovegrove (22kV load)

0.88 0.91 0.95 0.99 1.03 1.06 1.11 1.15 1.19 1.24

Lovegrove (66-22kV load)

32.50 32.21 32.35 32.49 32.63 32.65 32.80 33.12 33.29 33.48

Owen Springs Transmission Terminal Station

26.01 25.78 25.90 26.00 26.11 26.13 26.25 26.51 26.65 26.80

Sadadeen (Ron Goodin 11 kV Load)

19.47 19.48 19.76 20.03 20.31 20.51 20.80 21.20 21.50 21.82

40 Lovegrove (66-22kV load) and Owen Springs Transmission Terminal Station experience energy flows based on generation dispatch rather than customer demand due to their positions in the network.


B.4 Review of 2015-16 Actuals vs Forecasts at Zone Substation Level

Actual demand in 2015-16 is compared with the forecast demand as projected in the 2014-15 Power System Review.

Units Actual 50% POEProjection

Variation Comment

Darwin-Katherine MW 293.9 302.4 8.4

The projection was close to the actual. Archer MVA 27.2 25.6 -1.6 A 0.9MVA non-permanent transfer reduced the actual to 27.2

MVA. After correcting for the transfer, the difference increases to -2.53MVA., -9%. The difference is mainly attributed to interannual variability in demand.

Batchelor MVA 1.9 2.4 0.5 The projection was 28% higher than the actual. The difference is attributed to the selection of the starting point which was influenced by higher demand in 2011, 2012 and 2013.

Berrimah MVA 34.5 34.0 -0.5 The projection was close to the actual. However a non-permanent transfer raised the actual by 2.5MVA which suggests that the projection for normal operation could have been 2.5 MVA lower.

Casuarina MVA 50.7 32.2 -18.5 The actual was low due to a 0.64MVA non-permanent transfer. After correcting for this, the difference is -19.11MVA. A forecast transfer of 15MVA to Leanyer did not occur in 2016 but is now expected to occur in 2017.



Variation Comment

Centre Yard MVA 0.4 Projection not published. Cosmo Howley MVA 4.4 5.0 0.7 The projection is 15% higher than the actual. The forecast

reflected increasing industrial demand.

Darwin MVA 30.6 46.6 16.0 Projection published as 'City'. The projection was 52% higher than the actual. A load transfer of 14.5 MVA to Frances Bay occurred in 2016 resulting in the lower actual.

Frances Bay MVA 27.0 22.9 -4.1 The actual was low due to a 1.31MVA non-permanent transfer. After correcting for this, the difference is -5.4MVA. Inclusion of the load transfer from Darwin increased the projection, mitigating the difference to 19%.

Hudson Creek Transmission Terminal Station

MVA 225.5 Projection not published

Humpty Doo MVA 1.7 3.0 1.3 The projection was 81% higher than the actual. Historical demand is lower than 2MVA which suggests the projection was an overestimate.

Katherine MVA 28.1 30.6 2.5 A 0.63MVA non-permanent transfer increased the actual to 28.1MVA. After correcting for this, the difference increases to 3.1MVA.

Leanyer MVA Leanyer was not in service during 2015-16, commissioned in October 2016.

Manton MVA 2.5 8.5 6.0 The projection was higher than the actual. The projection was based upon the assumption that a block load was to proceed and increase demand in 2015-16. This was delayed until 2016-17.

Marrakai MVA 0.8 Projection not published



Variation Comment

Mary River MVA 2.9 4.7 1.8 The projection was 64% higher than the actual. Demand has increased to 2014-15 and plateaued in 2015-16.

McMinns/Strangways MVA 28.9 29.6 0.7 The projection was close to the actual.

Palmerston (22 - 11kV load) MVA 7.6 42.3 1.8 The projection was close to the actual.

Palmerston (66 - 11kV load) MVA 32.9

Pine Creek (22-11kV load) MVA 0.0 2.5 2.5 The actual was corrected from 0 to 1.06, resulting in a corrected difference of 1.44MVA. The difference is attributed to the choice of starting point.

Tindal (22kV load) MVA 4.8 7.6 2.8 Changes in load associated with the Tindal RAAF base did not eventuate.

Union Reef MVA 9.5 12.2 2.7 Overestimation. Maximum demands have been at and below 10MVA for the last 10 years.

Weddell MVA 6.6 12.8 6.2 Delay in customer connections meant the forecast included a block load that didn't affect demand in 2016. The block load is not forecast to affect MD in 2017.

Wishart Modular Substation MVA 3.5 Projection not published. The substation caters for a new transport hub. Further increases in demand are expected and represented in the updated forecasts.

Woolner MVA 38.0 36.9 -1.1 The projection was close to the actual. Alice Springs MW 53.1 54.9 1.8 The projection was close to the actual.



Variation Comment

Brewer + Sadadeen 22 kV Loads MVA 11.7 24.1 -14.5 Load transfer to Lovegrove occurred yet the projection was still higher than the actual (determined as the sum of the two

load groups).

Sadadeen (Ron Goodin 11 kV Load)

26.9

Lovegrove (22-11kV load) MVA 10.0 19.9 8.9 A temporary load transfer reduced the annual maximum of Lovegrove 11kV by 4.5MVA. After correcting for this the difference reduces to place projection 29% higher than the actual (determined as the sum of the two Lovegrove load groups).

Lovegrove (22kV load) 1.0

Lovegrove (66-22kV load) MVA 30.9 -30.9 Power at Lovegrove 66kV is determined by generation rather than demand.

Owen Springs Transmission Terminal Station

MVA 21.3 -21.3 Power at Owen Springs is determined by generation rather than demand.

Tennant Creek MW 6.8 6.9 0.1 The projection was close to the actual.


C Generator Related Load Shedding

Darwin-Katherine: Generator Outage Events that resulted in load shedding in 2015-16

Date Description Report Received for PSR

04/09/2015 Darwin-Katherine Power System - UFLS Stage 2B - Channel Island Unit 9 Tripped. YES

27/10/2015 Darwin-Katherine Power System - C8 and C9 tripped resulting under frequency load shed (UFLS) Stage 2A and 2B YES

02/12/2015 Weddell Power Station – UFLS Stage 2a – WPS Unit 1 and Unit 2 Tripped - Equipment Failure (Station air compressor) YES

Alice Springs: Generator Outage Events that resulted in load shedding in 2015-16


20/06/2015 UFLS Stage 1B. Ron Goodin Unit 9 gas changeover failure. YES

21/06/2015 Alice Springs Power System - UFLS Stage 1B - Owen Springs Unit 2 Tripped. YES

07/08/2015 Alice Springs Power System - UFLS Stage 1B - Ron Goodin Unit 3 Tripped. YES



01/10/2015Alice Springs Power System - UFLS Stage 1 - Owen Springs Unit 1 Tripped – Suspected Transformer Energisation Inrush Current.

YES

21/11/2015 Alice Springs Power System - UFLS Stage 2b - OSPS Unit 1 Tripped YES


03/01/2016 Alice Springs Power System - UFLS Stage 1A - OSPS Unit 2 Loss of Power YES

30/01/2016 Alice Springs Power System - System Black YES

04/03/2016Alice Springs Power System - UFLS Stage 1B - Owen Springs Power Station Unit 2 (O2) exhibited unstable oscillatory behaviour with a maximum output swing of 21 MW (+11MW to -10MW) resulting in UFLS Stage 1B.

YES

08/04/2016 Alice Springs Power System - OSPS Unit 2 and 3 Loss of Power- UFLS Stage 1B - Cause pending investigation YES

05/05/2016 Alice Springs Power System – UFLS Stage 1A and 1B - Loss of RGPS Unit 6 & Unit 7 – Equipment Failure YES

Tennant Creek: Generator Outage Events that resulted in load shedding in 2015-16


20/10/2015 Tennant Creek Power System - UFLS Stage 1 - Feeder Fault YES

02/11/2015 Tennant Creek Power System - UFLS Stage 1 - Unit 16, Feeder 2 and Feeder 6 Tripped (storm in area ) YES

13/11/2015Tennant Creek Power Station - UFLS Stage 1 – Load Shedding - Fire detector shut down Tennant Creek Generation Set 16

YES

19/11/2015 Tennant Creek Power System - UFLS Stage 1 - Feeder 2 and Feeder 6 Tripped (Fire Alarm, Set 16 Tripped ) YES

21/11/2015 Tennant Creek Power Station - UFLS Stage 1 - Feeder 2 and Feeder 6 Tripped (Fire Alarm, Set 16 Tripped) YES

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